Text

Request for License Amendment Regarding Core Flow Operating Range Expansion
	ML16257A410
Person / Time
Site:	Brunswick
Issue date:	09/06/2016
From:	William Gideon; Duke Energy Progress
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML16257A418	List: BSEP 16-0056, ANP-3108(NP), Revision 1, Applicability of Areva BWR Methods to Brunswick Extended Power Flow Operating Domain; ML16257A404; ML16257A406; ML16257A407; ML16257A408; ML16257A410; ML16257A411;
References
	BSEP 16-0056
	Download: ML16257A410 (75)
	v • d • e

J_~DUKE

~ ENERGY William R. Gideon Vice President Brunswick Nuclear Plant P.O. Box 10429 Southport, NC 28461 September 6, 2016 Serial: BSEP 16-0056 U.S. Nuclear Re*gulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Brunswick Steam Electric Plant, Unit Nos. 1 and 2 Renewed Facility Operating License Nos. DPR-71 and DPR-62 Docket Nos. 50-325 and 50-324 Request for License Amendment Regarding Core Flow Operating Range Expansion Ladies and Gentlemen:

o: 910.457.3698 In accordance with the provisions of Title 1 O of the Code of Federal Regulations (1 O CFR Part 50.90), Applications for Amendment of License, Construction Permit, or Early Site Permit, Duke Energy Progress, Inc. (Duke Energy), hereby requests a revision to the Technical Specifications (TSs) for the Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2. The proposed license amendments revise TSs 3.1. 7, 3.3.1.1, 3.4.1, 5.6.5, add a new TS 5.6. 7, and add a new condition to Appendix B of the operating license (OL), to support an expansion of the core power-flow operating range (i.e., Maximum Extended Load Line Limit Analysis Plus (MELLLA+)).

There are no major plant hardware modifications associated with this license amendment request (LAR); however, it does involve changes to the operating power/flow map, changes to a number of instrument Allowable Values and setpoints, and to the current reactor core stability solution. Because there is no change in reactor operating pressure, reactor power, steam flow rate, or feedwater flow rate, there is no significant effect on plant hardware outside the Nuclear Steam Supply System. contains the description of the proposed changes to the TS and the basis for the new proposed license condition. This enclosure also includes the technical evaluation and the associated no significant hazards analysis and environmental evaluation. contains marked-up Unit 1 TS and OL Appendix B pages indicating the proposed changes.

Enciosure 3 contains marked-up Unit 2 TS and OL Appendix B pages indicating the proposed changes. contains a draft markup of the changes to the associated Unit 1 TS Bases for information only. Duke Energy plans to implement these changes in accordance with

U.S. Nuclear Regulatory Commission Page 2of6 BSEP TS 5.5.10, "Technical Specifications Bases Control Program," once this LAR is approved.

Enclosures 5 and 6, respectively, contain proprietary and non-proprietary versions of a Duke Energy document: Safety Analysis Report for Brunswick Steam Electric Plant Units 1and2 Maximum Extended Load Line Limit Analysis Plus (i.e., MELLLA+ Safety Analysis Report (M+SAR)).

Enclosures 7, 8, and 9 provide affidavits supporting the withholding from public disclosure of information in the M+SAR that is considered proprietary by General Electric-Hitachi (GE-H), AREVA NP (AREVA), and the Electric Power Research Institute (EPRI), respectively. 0 provides a list of regulatory commitments associated with implementation of an expanded core power-flow operating range. 1 provides discussion of the issues outlined in SECY-11-0014 regarding containment accident pressure (CAP), and describes the Net Positive Suction Head (NPSH) margin calculations performed by Duke Energy as an adjunct to the MELLL,A+

licensing submittal.

Enclosures 12, 15, 18, 21, and 24 provide proprietary topical reports that support the MELLLA+ licensing submittal. Enclosures 13, 16, 19, 22, and 25 provide non-proprietary versions of these topical reports. Enclosures 14, 17, 20, 23, and 26 provide affidavits supporting the withholding of the proprietary documents from public disclosure.

The BSEP M+SAR is an integrated summary of the safety analyses and evaluations performed specifically in support of this LAR. The M+SAR contains information which GE-H, AREVA, and EPRI consider to be proprietary. GE-H, AREVA, and EPRI request that the proprietary information in this report be withheld from public disclosure in accordance with 10 CFR 9.17(a)(4) and 10 CFR 2.390(a)(4). The NRC may duplicate this submittal, including the M+SAR, for the purpose of internal review.

As part of MELLLA+ implementation for BSEP, Duke Energy will implement the Detect and Suppress Solution - Confirmation Density (DSS-CD) approach to automatically detect and suppress neutronic/thermal-hydraulic instabilities (THI). DSS-CD represents an evolutionary step from the Boiling Water Reactor Owners' Group (BWROG) Option Ill Reactor Stability Long-Term Solution, currently approved for use at BSEP. The M+SAR discusses this change and verifies the applicability of GE-H Report NEDC-33075P-A, GE Hitachi Boiling Water Reactor Detect And Suppress Solution - Confirmation Density, Revision 8, dated November 2013 (i.e.,

Reference 7.4 of Enclosure 1), to BSEP, Units 1 and 2. Upon issuance of MELLLA+ for BSEP, the Backup Stability Protection (BSP) described in NEDC-33075P-A will be the preferred alternate method to detect and suppress THI oscillations as allowed by TS 3.3.1, 1, Action I. The proposed license amendments revise the TSs, as necessary, to support implementation of DSS-CD at BSEP.

Duke Energy has evaluated the proposed change in accordance with 10 CFR 50.91 (a)(1 ), using the criteria in 10 CFR 50.92(c), and determined that this change involves no significant hazards consideration.

/

U.S. Nuclear Regulatory Commission Page 3 of 6 Duke Energy plans to implement the proposed license amendment for Unit 1 during Cycle 22 (i.e., Cycle 22 is currently scheduled to begin in March 2018) and for Unit 2 prior to the end of Cycle 23 (i.e., before the Unit 2 refueling outage scheduled to begin in March 2019). To support this schedule, Duke Energy requests approval of the proposed license amendment by September 28, 2018, with the amendment being implemented within 120 days.

In accordance with 10 CFR 50.91, Duke Energy is providing a copy of the proposed license amendment to the designated representative for the State of North Carolina.

Please refer any questions regarding this submittal to Mr. Lee Grzeck, Manager - Regulatory Affairs, at (910) 457-2487.

I declare, under penalty of perjury, that the foregoing is true and correct. Execute on September 6, 2016.

s~

William R. Gideon

U.S. Nuclear Regulatory Commission Page 4of6

Enclosures:

1. Evaluation of Proposed License Amendment Request

2. Brunswick Unit 1 Technical Specification and Operating License Appendix B Mark-ups

3. Brunswick Unit 2 Technical Specification and Operating License Appendix B Mark-ups

4. Brunswick Unit 1 Technical Specification Bases Mark-ups (For Information Only)

5. Duke Energy, Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2 Maximum Extended Load Line Limit Analysis Plus (M+SAR), DUKE-OB21-1104-000(P),

July 2016 [Proprietary Information - Withhold from Public Disclosure in Accordance With 10 CFR 2.390]

6. Duke Energy, Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2 Maximum Extended Load Line Limit Analysis Plus (M+SAR),

DUKE-OB21-1104-000(NP), July 2016

7. Affidavit from General Electric-Hitachi (GE-H) Regarding Withholding DUKE-OB21-1104-000(P), Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2 Maximum Extended Load Line Limit Analysis Plus

8. Affidavit from AREVA NP Regarding Withholding DUKE-OB21-1104-000(P), Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2 Maximum Extended Load Line Limit Analysis Plus

9. Affidavit from Electric Power Research Institute (EPRI) Regarding Withholding DUKE-OB21-1104-000(P), Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2 Maximum Extended Load Line Limit Analysis Plus

10. List of Regulatory Commitments

11. SECY-11-0014 Discussion - Use of Containment Accident Pressure (CAP) in Analyzing ECCS and Containment Heat Removal System Pump Performance

12. ANP-3108P, Revision 1, Applicability of AREVA BWR Methods to Brunswick Extended Power Flow Operating Domain, July 2015 [Proprietary Information - Withhold from Public Disclosure in Accordance With 10 CFR 2.390]

13. ANP-3108NP, Revision 1, Applicability of AREVA BWR Methods to Brunswick Extended Power Flow Operating Domain, July 2015

14. AREVA NP Affidavit Regarding Withholding ANP-3108P, Revision 1, Applicability of AREVA BWR Methods to Brunswick Extended Power Flow Operating Domain, July 2015

15. ANP-3280P, Revision 1, Brunswick Unit 1Cycle19 MELLLA+ Reload Safety Analysis, May 2016 [Proprietary Information - Withhold from Public Disclosure in Accordance With 1 O CFR 2.390]

16. ANP-3280NP, Revision 1, Brunswick Unit 1Cycle19 MELLLA+ Reload Safety Analysis, May 2016

17. AREVA NP Affidavit Regarding Withholding ANP-3280P, Revision 1, Brunswick Unit 1 Cycle 19 MELLLA+ Reload Safety Analysis, May 2016

18. ANP-3106P, Revision 2, Brunswick Units 1and2 LOCA-ECCS Analysis MAPLHGR Limit for A TR/UM 1 OXM Fuel for MELLLA + Operation, December 2015 [Proprietary Information -Withhold from Public Disclosure in Accordance With 10 CFR 2.390]

19. ANP-3106NP, Revision 2, Brunswick Units 1and2 LOCA-ECCS Analysis MAPLHGR Limit for A TR/UM 10XM Fuel for MELLLA+ Operation, December 2015

U.S. Nuclear Regulatory Commission Page 5 of 6

20. AREVA NP Affidavit Regarding Withholding ANP-3106P, Revision 2, Brunswick Units 1 and 2 LOCA-ECCS Analysis MAPLHGR Limit for ATRIUM 10XM Fuel for MELLLA+

Operation, December 2015

21. ANP-3013P, Revision 0, Brunswick Unit 1Cycle19 Fuel Cycle Design MELLLA+

Operating Domain, May 2013 [Proprietary Information - Withhold from Public Disclosure in Accordance With 1 O CFR 2.390]

22. ANP-3013NP, Revision 0, Brunswick Unit 1Cycle19 Fuel Cycle Design MELLLA+

Operating Domain, May 2013

23. AREVA NP Affidavit Regarding Withholding ANP-3013P, Revision 0, Brunswick Unit 1 Cycle 19 Fuel Cycle Design MELLLA+ Operating Domain, May 2013

24. ANP-3105P, Revision 1, Brunswick Units 1 and 2 LOCA Break Spectrum Analysis for ATRIUM 10XM Fuel for MELLLA+ Operation,. July 2015 [Proprietary Information -

Withhold from Public Disclosure in Accordance With 10 CFR 2.390]

25. ANP-3105NP, Revision 1, Brunswick Units 1 and 2 LOCA Break Spectrum Analysis for ATRIUM 10XM Fuel for MELLLA+ Operation, July 2015

26. AREVA NP Affidavit Regarding Withholding ANP-3105P, Revision 1, Brunswick Units 1 and 2 LOCA Break Spectrum Analysis for A TR/UM 10XM Fuel for MELLLA+ Operation, July 2015

U.S. Nuclear Regulatory Commission Page 6 of 6 cc (with all enclosures):

U.S. Nuclear Regulatory Commission, Region II ATTN: Ms. Catherine Haney, Regional Administrator 245 Peachtree Center Ave, NE, Suite 1200 Atlanta, GA 30303-1257 U.S. Nuclear Regulatory Commission ATTN: Mr. Andrew Hon (Mail Stop OWFN 8G9A) (Electronic Copy Only) 11555 Rockville Pike Rockville, MD 20852-2738 U.S. Nuclear Regulatory Commission ATTN: Ms. Michelle P. Catts, NRC Senior Resident Inspector 84 70 River Road Southport, NC 28461-8869 cc (with Enclosures 1 through 4, 6 through 11, 13, 14, 16, 17, 19, 20, 22, 23, 25, 26):

Mr. W. Lee Cox, Ill, Section Chief (Electronic Copy Only)

Radiation Protection Section North Carolina Department of Health and Human Services 1645 Mail Service Center Raleigh, NC 27699-1645 lee.cox@dhhs.nc.gov Chair - North Carolina Utilities Commission (Electronic Copy Only) 4325 Mail Service Center Raleigh, NC 27699-4300 swatson@ncuc.net

Evaluation of Proposed License Amendment Request

Subject:

Core Flow Operating Range Expansion 1.0 Description BSEP 16-0056 Page 1of16 This letter is a request to amend Renewed Facility Operating Licenses DPR-71 and DPR-62 for the Brunswick Steam Electric Plant (BSEP), Units 1 and 2. In accordance with 10 CFR 50.90, Duke Energy Progress, Inc. (Duke Energy) proposes to revise the Operating Licenses (OL) and Technical Specificatipn_s (TS) for BS~P. Units 1 and 2, to allow plant operation in the expanded Maximum Extended Load Line Limit Analysis Plus (MELLLA+) domain with the Detect and Suppress Solution - Confirmation Density (DSS-CD) long-term reactor core thermal-hydraulic stability solution.

The proposed license amendments revise the TSs and OLs to: (1) support an expansion of the core flow operating range, (2) implement the Detect and Suppress Solution - Confirmation Density (DSS-CD) approach to automatically detect and suppress neutronic/thermal-hydraulic instabilities (THI), and (3) increase the minimum boron-10 (B-10) enrichment in the sodium pentaborate (SPB) solution from~ 47 atom-percent to~ 92 atom-percent and decrease the minimum required SPB solution volume. These changes support operation of Units 1 and 2 at 2923 megawatts thermal (MWt) with core flow as low as 85 percent of rated core flow (i.e.,

MELLLA+). contains Duke Energy Report Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2 Maximum Extended Load Line Limit Analysis Plus (M+SAR). This report provides the technical bases for this request and contains an integrated summary of the results of the underlying safety analyses and evaluations performed specifically for BSEP, Units 1 and 2. The M+SAR follows the guidelines contained in the generic MELLLA+ Licensing Topical Report (M+LTR), NEDC-33006P-A (i.e., Reference 7.2). Although the M+LTR is a product of General Electric-Hitachi (GE-H), BSEP currently operates with AREVA fuel. As such, the safety evaluations provided in the M+SAR are the results of analyses from both GE-Hand AREVA.

2.0 Proposed Change Duke Energy requests the following TS changes (i.e., OL Appendix A) and OL condition changes (i.e., OL Appendix B). The proposed changes support the MELLLA+ expansion of the core flow operating range and implement the DSS-CD approach to automatically detect and suppress THI for BSEP, Units 1 and 2. Enclosures 2 and 3 contain marked-up OL pages for Units 1 and 2, respectively. Duke Energy will make supporting changes to the TS Bases in accordance with TS 5.5.10, Technical Specifications (TS) Bases Control Program. Enclosure 4 provides the marked-up TS Bases pages for Unit 1. These pages are being submitted for information only and do not require issuance by the NRC. Unit 2 will require similar changes.

The following OL and TS sections are affected by this change:

TS 3.1.7, Standby Liquid Control (SLC) System TS 3.3.1.1, Reactor Protection System (RPS) Instrumentation TS 3.4.1, Recirculation Loops Operating TS 5.6.5, Core Operating Limits Report (COLR)

TS 5.6. 7, Oscillation Power Range Monitor (OPRM) Report (i.e., new section)

BSEP 16-0056 Page 2 of 16 OL Appendix B, Additional Conditions (i.e., new condition addressing operations with reduced feedwater temperature)

The following table identifies the specific OL including the TS sections being changed, a description of the change, the reference to documentation justifying the change, and any pertinent comments.

Proposed Technical Specification Changes -

MELLLA+

Specification TS 3.1.7, Standby Liquid Control System SR 3.1.7.8 Figure 3. 1. 7-1 TS 3.3.1.1, Reactor Protection System {RPS)

Instrumentation Required Action I. 1 Required actions 1.2and1.3 (NEW)

TS 3.3.1.1, Reactor Protection System {RPS)

Instrumentation Required Action J. 1 Required actions J.2 and J.3 (NEW)

.i Existing Requirement Verify the sodium pentaborate enrichment is~ 47 atom-percent B-10.

Figure based on 47 atom-percent B-1 O enrichment.

1.1 Initiate alternate method to detect and suppress thermal hydraulic instability oscillations.

(Completion Time: 12 Hours)

None Reduce THERMAL POWER to <20% RTP.

(Completion Time: 4 Hours)

None Proposed Requirement Verify the sodium pentaborate enrichment is ~ 92 atom-percent B-10.

Figure replaced by new figure based on 92 atom-percent B-10 enrichment 1.1 Initiate action to implement the Manual BSP Regions defined in the COLR.

AND 1.2 AND (Compl~tion Time: Immediately)

Implement the Automated BSP Scram Region using the modified APRM Simulated Thermal Power - High scram setpoints defined in the COLR.

(Completion Time: 12 Hours) 1.3 Initiate action in accordance with Specification 5.6.7.

(Completion Time: Immediately)

J.-1 AND Initiate action to implement the Manual BSP Regions defined in the COLR.

(Completion Time: Immediately)

J.2 Reduce operation to below the BSP Boundary defined in the COLR.

J.3 (Completion Time: 12 Hours)

AND J

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

LCO 3.0.4 is not applicable Restore required channel to OPERABLE.

(Completion Time: 120 days)

Comments/Justification BSEP 16-0056 Page 3 of 16 License Amendment Request (LAR)

Section 4.2, M+SAR Section 4.2.6 LAR Section 4.2, M+SAR Section 4.2:6 M+SAR 2.4.3 and proposed changes per Reference 7.4, Table 8-1.

M+SAR Section 2.4.3 and proposed changes per Reference 7.4, Table 8-1.

Proposed Technical Specification Changes -

MELLLA+

Specification TS 3.3.1.1, Reactor Protection System (RPS)

Instrumentation Condition K (New)

Required Action K. 1 TS 3.3.1.1, Reactor Protection System (RPS)*

Instrumentation SR 3.3.1.1.19 TS 3.3.1.1, Reactor Protection System (RPS)

Instrumentation Table 3.3.1.1-1 Function 2.b (Average Power Range Monitors, Simulated Thermal Power - High) Allowable Value Function 2.f (OPRM Upscale)

Applicable Modes or other Specified Conditions Allowable Value Footnote ( d)

Existing Requirement None None Verify OPRM is not bypassed when APRM Simulated Thermal Power is ~ 25% and recirculation drive flow is ::;; 60%.

s;0.55W+62.6% RTP(bl and s;117.1% RTP

~20% RTP Proposed Requirement Required Action and associated Completion Time of Condition J not met.

K.1 Reduce THERMAL POWER to ::;;18% RTP.

(Completion Time: 4 Hours)

Deleted s;0.61W+65.2% RTP(bJ(el and

117.1% RTP New Note ( e )

(e)

With OPRM Upscale (Function 2.f) inoperable, the Automated BSP Scram Region setpoints are implemented in accordance with Action I of this Specification.

~18% RTP<fl (f)

Following DSS-CD implementation, DSS-CD is not required to be armed while in the DSS-CD Armed Region during the first reactor startup and during the first controlled shutdown that passes completely through the DSS-CD Armed Region. However, DSS-CD is considered OPERABLE and shall be maintained OPERABLE and capable of automatically arming for operation at recirculation drive flow rat~s above the DSS-CD Armed Region.

(d)

(d) See COLR for OPRM period based detection (d}

. See COLR for OPRM Confirmation Density Algorithm (CDA) setpoints.

algorithm (PBDA) setpoint limits.

Comments/Justification BSEP 16-0056 Page 4of16 Proposed changes per Reference 7.4, Table 8-1.

As discussed in Reference 7.4, DSS-CD automatically arms and the surveillance is unnecessary per Reference 7.4, Table 8-1.

Based on Analytical Values presented in the M+SAR Section 5.3.1 with traditional setpoint methodology applied Proposed changes per Reference 7.4, Table 8-1.

As discussed in Reference 7.4, the DSS-CD is required to be operable above a power level set at 5% of rated power below the lower boundary df the Armed Region defined by the MCPR monitoring threshold power level. (i.e., 23% per TS 3.2.2 and Section 2.4.2 of the M+SAR).

Proposed changes per Reference 7.4, Table 8-1.

DSS-CD setpoints are in the COLR.

Proposed Technical Specification Changes -

MELLLA+

Specification Existing Requirement Function 2.f Surveillance Requirements SR 3.3.1.1.19 -

Verify OPRM is not bypassed when APRM Simulated Thermal Power is <:: 25% and recirculation drive flow is::;; 60%.

TS 3.4.1, Recirculation Loops Operating LCO 3.4.1 One recirculation loop may be in operation provided the following limits are applied when the associated LCO is applicable:

TS 3.4.1, Recirculation Loops Operating New Condition B B.

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

OR No recirculation loops in operation.

New Action B. 1 B.1 Be in MODE 3.

(Completion Time: 12 Hours)

New (:;ondition C Action B. 1 is renamed C. 1.

TS 5.6.5, CORE OPERATING LIMITS REPORT

a.

Core operating limits shall be established prior to each reload cycle, or prior to any remaining portion of a reload cycle, and shall be documented in the COLR for the following:

Item 4:

4.

The period based detection algorithm (PBDA) setpoint for Function 2.f, Oscillation Power Range Monitor (OPRM)

Upscale, for Specification 3.3.1.1; and Proposed Requirement Deleted One recirculation loop may be in operation provided the plant is not operating in the MELLLA+ operating domain and provided the following limits are applied when the associated LCO is applicable:

B.

Operation in the MELLLA+ domain with a single recirculation loop in operation.

B.1 Initiate action to exit the MELLLA+ domain.

(Completion Time: Immediately)

C.

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

OR No recirculation loops in operation.

C.1 Be in MODE 3.

(Completion Time: 12 Hours)

4.

The Manual Backup Stability Protection (BSP) Scram Region (Region I), the Manual BSP Controlled Entry Region (Region II), the modified APRM Simulated Thermal Power - High scram setpoints used in the Automated BSP Scram Region, the BSP Boundary for Specification 3.3.1.1, and Comments/Justification BSEP 16-0056 Page 5of16 See SR 3:3.1.1.19. Proposed changes per Reference 7.4, Table 8-1.

Per the M+SAR Section 3.6.3, single loop operation (SLO) is prohibited -in the MELLLA+

operating domain.

Revised Condition B to clarify that immediate action is necessary to exit the MELLLA+

region when operating in SLO.

Administrative change$ to reflect renaming the old Condition B-to Condition C.

Included failure to perfo~m the new Action B.

Consistent with TS 5.6.5 requiring reload cycle dependent limits to be documented in the COLR. Proposed changes consistent with Reference 7.4, Table 8-1.

Proposed Technical Specification Changes...,

MELLLA+

Specification Existing Requirement TS 5.6.5, CORE OPERATING LIMITS REPORT

b.

The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:

Item 19:

19.

NED0-32465-A, Reactor Stability Detect and Suppress Solutions Licensing Basis Methodology for Reload Applications.

TS 5.6. 7, OPRM Report None (New Technical Specification)

/

Proposed OL Additional Conditions Changes -

MELLLA+

Operating License Paragraph Existing Requirement OL 3. Additional Conditions -Appendix B Additional Conditions None Implementation Date N/A Proposed Requirement

19.

NEDC-33075P-A, GE Hitachi Boiling Water Reactor, Detect and Suppress Solution - Confirmation Density, Revision 8, November 2013 (i.e., Reference 7.4).

When a report is required by Condition I of LCO 3.3.1.1, RPS Instrumentation, a report shall be submitted within the following 90 days. The report shall outline the preplanned means to provide backup stability protection, the cause of the inoperability, and the plans and schedule for restoring the required instrumentation channels to OPERABLE status.

Proposed Requirement The licensee stjall not operate the facility within the MELLLA+

operating domain with Feedwater Temperature'Reduction (FWTR), as defined in the.core Operating Limits Report.

Comm.entslJustification BSEP 16-0056 Page 6of16 Revised to reflect the DSS-CD stability solution. The Period Based Detection Algorithm will no longer be credited in the safety analysis.

See LCO 3.3.1.1,,Required Action 1.3.

Proposed changes per Reference 7.4, Table 8-1.

Comments/Justification M+SAR Section 1.2.4 The new condition includes a requirement to define FWTR in the COLR.

3.0

Background

BSEP 16-0056 Page 7of16 The BSEP 120 percent Extended Power Uprate (EPU) approved by the NRC reduced the licensed flow window at 100 percent power from approximately 24 percent to 6 percent (i.e.,

Reference 7.1 ). Duke Energy is requesting a license amendment to restore the licensed flow window at 100 percent power to approximately 20 percent. The proposed changes revise the OL and TS for BSEP, Units 1 and 2, to allow plant operation in the MELLLA+ domain with the stability DSS-CD. The changes also revise the SLC TS to require the use of~ 92 atom-percent enriched B-10, which supports operation in the MELLLA+ region.

The primary benefits of this project are to recover flow margin lost as a result of EPU and a reduction in challenges to reactivity management. Changes in reactivity over an operating cycle are controlled with the use of control rod blades or core flow rate. Since control blade manipulations are performed at less thari rated power, the expanded flow window significantly reduces the number of plant maneuvers required to maintain full power operation. With the expanded flow window, the number of rod adjustments required to maintain full power operation is expected to be reduced by approximately 40 percent over a typical operating cycle.

While the larger MELLLA+ flow window can clearly provide the strategic benefit of reduced control blade manipulation and the subsequent reduction in challenges to reactivity management, the expanded flow window also improves fuel reliability. Controlling core reactivity globally via recirculation flow changes is inherently more gentle to fuel than controlling core reactivity via control rod position changes and the associated localized power increases.

4.0 Technical Analysis 4.1 MELLLA+ Operation The technical analyses and justification for the proposed changes are provided in the M+SAR (i.e., Enclosure 5). The M+SAR summarizes the results of the significant safety evaluations performed that justify:

(1) Implementing the MELLLA+ expanded operating domain; (2) Changing the BSEP stability solution from Option Ill to DSS-CD; (3) Applying the GE-H TRACG04 analysis code to DSS-CD; (4) The acceptability of AREVA ATRIUM 10XM fuel for MELLLA+ conditions; and (5) The application of AREVA methods to the MELLLA+ operating domain.

The M+SAR is based on the M+L TR, the DSS-CD L TR, and the GE-H Methods L TR and the AREVA Methods Report (i.e., Reference 7.5). The evaluations contained in the M+SAR demonstrate that BSEP can safely operate in the MELLLA+ expanded operating domain, using the DSS-CD stability solution, in adherence to the requirements of these documents.

The DSS-CD stability solution discussed in the M+L TR Safety Evaluation Report (SER) (i.e.,

Reference 7.2) was chosen for use at BSEP and is being implemented using the guidelines contained in the DSS-CD LTR (i.e., Reference 7.4). The results of the DSS-CD evaluation and the use of TRACG04 are provided in M+SAR Section 2.4 and in Reference 7.4. Likewise, the acceptability of DSS-CD using ATRIUM 10XM fuel is addressed in M+SAR Section 2.4.1. The acceptability of ATRIUM 10XM fuel and AREVA methods to MELLLA+ operation is addressed in M+SAR Section 2.1.1 and 2.6.3.

4.2 TS 3.1. 7, Standby Liquid Control (SLC) System BSEP 16-0056 Page 8of16 As described in Section 9.3.4 of.the BSEP Updated Final Safety Analysis Report (UFSAR), the SLC system is designed to provide backup capability for reactivity control independent of normal reactivity control to permit shutdown of the reactor. To assure complete shutdown from the most reactive condition at any time in the core life, the SLC system has the capacity to control the reactivity difference between the steady state rated operating condition of the reactor with voids and the cold shutdown condition, including shutdown margin. The neutron absorber is dispersed within the reactor core in sufficient quantity to provide a reasonable margin for leakage, dilution, or imperfect mixing. The SLC system is also used to maintain suppression pool pH level above seven following a loss of coolant accident (LOCA) involving significant fission product releases.

Maintaining suppression pool pH levels greater than seven following an accident ensures that iodine will be retained in the suppression pool water as reflected in the LOCA dose analysis.

The SLC system consists of an SPB solution storage tank, two positive displacement pumps, two explosive valves, and associated piping and valves used to transfer the SPB solution from the storage tank to the reactor pressure vessel. The boron solution is piped into the reactor vessel and discharged near the botfom of the core shroud so it mixes with the cooling water rising through the core. The boron absorbs thermal neutrons and thereby terminates the nuclear fission chain reaction. The SLC system is required only to shut the reactor down at a steady rate within the capacity of the shutdown cooling systems, and keep the reactor from going critical again as it cools.

Current compliance with 10 CFR 50.62 to address anticipated transient without scram (ATWS) concerns is based on a reduced flow requirement (i.e., 43 gpm), a reduced chemical concentration (i.e., ;;:: 8.5 weight-percent), and an increased boron-10 enrichment (i.e.,

47 atom-percent). Given that the existing BSEP SLC system operates both SLC pumps simultaneously to satisfy 10 CFR 50.62 requirements, the 86 gpm system design flow rate greatly exceeds the 43 gpm required to meetJhe equivalency equation described in UFSAR Section 9.3.6.4.

BSEP Unit 1 increased the B-10 enrichment from ;;:: 47 atom-percent to ;;:: 92 atom-percent during the Spring 2016 refueling outage. The TSs for the SLC system were not impacted by the change to the higher enrichment because all requirements associated with the current operating domain continue to be met and ensure the SLC system is capable of fulfilling its intended safety function for the current operating domain. Specifically, the system parameters of flow rate, net volume of SLC solution,* solution concentration, and temperature limitations are maintained in accordance with the existing design requirements and existing TS 3.1. 7. The proposed changes to the TSs compliment the changes already implemented by revising the required enrichment of SR 3.1.7.8 and revising Figure 3.1.7-1 to reflect a decrease in the required volume associated with using ;;:: 92 atom-percent enriched boron. The system flow rate, the range of allowed concentrations (i.e., Figure 3.1.7-1) and the allowed temperatures (i.e., Figure 3.1.7-2) for the stored sodium pentaborate solution do not change. BSEP Unit 2 will implement the SLC system enrichment increase to;;:: 92 atom-percent boron-10 during the 2017 Refueling Outage.

4.2.1 B-1 O Enrichment and Shutdown Requirements Adequate shutdown margin is currently reached by injecting a quantity of boron that produces the equivalent of a concentration of at least 720 ppm of natural boron in the

BSEP 16-0056 Page 9of16 reactor core at 70°F with normal reactor vessel water level. To allow for potential imperfect mixing and leakage, the amount of boron is increased by 25 percent above 720 ppm required for shutdown. The SLC system changes and their impact on shutdown margin are described in the M+SAR, Section 6.5.1. The minimum reactor coolant concentration of 720 ppm natural boron does not change as a result of MELLLA+

operation. The increase in B-10 enrichment from 47 atom-percent to 92 atom-percent does not impact the 720 ppm requirement to achieve the required shutdown margin.

With the increased enrichment, the quantity of SLC solution necessary to reach the equivalent of 720 ppm of natural boron is reduced.This is reflected in the revised TS Figure 3.1. 7-1. The volume requirements reflected in the proposed figure are based on 92 atom-percent enriched B-10 in the SLC solution. The range of concentrations (8.5 weight-percent to 10.5 weight-percent) and the solution temperature requirements of TS Figure 3.1. 7-2 are unchanged. Therefore, the SLC system's ability to meet the shutdown margin requirement is not affected by the proposed changes to TS 3.1. 7.

4.2.2 Anticipated Transient Without Scram (ATWS) Requirements An anticipated transient without scram (A TWS) is defined as an anticipated operational occurrence (AOO) followed by the failure of the reactor trip portion of the protection system specified in 10 CFR 50, Appendix A, General Design Criterion (GDC) 20.

1 O CFR 50.62, Requirements for reduction of risk from A TWS events for light-water-cooled nuclear power plants, requires, in part, that:

Each BWR must have a SLC system with the capability of injecting into the reactor vessel a borated water solution with reactivity control at least equivalent to the control obtained by injecting 86 gpm of a 13 weight-percent sodium pentaborate decahydrate solution at the natural boron-10 isotope abundance into a 251-inch inside diameter reactor vessel. The SLC system initiation must be

automatic (for plants granted a construction permit after July 26, 1984).

As discussed in the BSEP UFSAR Section 9.3.4.6, the current compliance with 10 CFR 50.62 is based on a flow rate of 43 gpm, the minimum allowed chemical concentration (i.e., 8.5 weight percent), and a minimum boron-10 enrichment of 47 atom-percent. Using the new minimum enrichment of 92 atom-percent in the equivalency equation of UFSAR 9.3.6.4 (i.e., result must be greater than 1.0 to demonstrate equivalency), the result goes from 1.004 to 1.966. Therefore, the requirements of 10 CFR 50.62 continue to be satisfied while adding margin to this requirement.

Additional margin is added by operating two pumps simultaneously as described in UFSAR 9.3.4.3.

4.2.3 Post-LOCA Suppression Pool pH Control As discussed above and in the Safety Analysis section of the BSEP TS 3.1. 7 Bases, another function of the SLC system is to maintain suppression pool pH level following a LOCA involving significant fission product releases. Following a LOCA, offsite doses from the accident will remain within 1 O CFR 50.67 limits provided sufficient iodine activity is retained in the suppression pool. Credit for iodine deposition in the suppression pool is allowed as long as suppression pool pH is maintained greater than seven. BSEP

BSEP 16-0056 Page 10 of 16 Alternative Source Term analyses credit the use of the SLC system for maintaining the pH of the suppression pool greater than seven.

As discussed in 4.2.1 above, the volume of sodium pentaborate solution required to meet shutdown requirements is reduced with the increased B-10 enrichment. The minimum volume requirements of new TS Figure 3.1.7-1 were determined based on shutdown margin requirements and bound the amount of sodium pentaborate needed to ensure the post-LOCA suppression pool pH is maintained greater than seven. As discussed in the M+SAR, Section 9.2.1.4, the MELLLA+ operating domain expansion does not affect the source term assumptions. As a result, the Alternative Source Term radiological analyses are not impacted and the requirements of 1 O CFR 50.67 continue to be satisfied.

4.3 Recirculation System Flow Anomalies In March 2006, General Electric Energy, Nuclear (GE) issued Service Information Letter (SIL) 467, Revision 1, Recirculation System Bi-Stable Flow in Jet Pump BWRs. This SIL described a condition where random recirculation loop flow fluctuations have been observed in several BWRs during steady state operation. These changes produce corresponding changes in core flow, core power, and electrical output. The condition is attributed to a bi-stable flow pattern at the jet pump header cross in the recirculation pump discharge piping. One of the two flow patterns has larger hydraulic losses than the other causing the observed flow changes. GE evaluated the impact of this condition and concluded that there are no safety concerns and minimal impact to plant equipment.

The bi-stable flow condition reported in SIL 467 has been observed at BSEP and the magnitude of the flow variations are below the threshold for concern. The SIL recommended actions were implemented at BSEP. No recent operational events attributed to recirculation system bi-stable flow have been identified at BSEP. As discussed in the M+SAR Section 3.6, there are no increases in recirculation system temperature, pressure, or flow rates as q result of the MELLLA+ operating domain expansion as compared to the current licensed operating domain.

As discussed in the SIL, the factors affecting bi-stable flow are the hydraulic resistance characteristics that the recirculation pump experiences between the pump discharge and the exit of the jet pump nozzles. Since operation in the MELLLA+ region only indirectly impacts these characteristics, the changes in the frequency or magnitude of recirculation flow disturbances attributable to bi-stable flow at BSEP are not expected. The MELLLA+ Startup Test Program discussed in the M+SAR Section 10.4 monitors for the effects of bi-stable flow.

Specifically, the core performance testing will evaluate the core thermal power, fuel thermal margin, and core flow performance to ensure a monitored approach to current licensed thermal power (CL TP) in the MELLLA+ operating domain. Neutron flux noise data is collected and analyzed to verify that average core power and neutron flux noise levels are within expectations in the MELLLA+ operating dsmain.

4.4 Instrument Uncertainty Two TS RPS functions are changing in this amendment: (1) the Oscillation Power Range Monitor (OPRM) - Upscale function, and (2) the Average Power Range Monitor (APRM) - Flow Biased Simulated Thermal Power (STP) - Upscale function. The OPRM setpoints are unique to a particular core design for a particular fuel cycle. As described in the proposed TS Bases, the

BSEP 16-0056 Page 11of16 OPRM function setpoints do not have traditional TS allowable values (AVs). The OPRM Upscale Function is not Limiting Safety System Setting (LSSS) Safety Limit (SL)-related (NEDC-33075P-A). OPRM uncertainties are discussed in more detail in the M+SAR section 2.4.1.

The APRM - Flow Biased Simulated Thermal Power - Upscale function is used for the Automated Backup Stability Protection (ABSP) if the OPRM becomes inoperable. The APRM STP-High AV in the TS and the Nominal Trip Setpoint are developed based on a specific setpoint methodology that ensures the APRM STP Upscale function actuates at the point assumed in the safety analysis. The APRM STP Upscale as-found and as-left setpoints are maintained and tested by controlled plant surveillance procedures. The surveillance testing practices ensure that this function is considered to be properly adjusted when the "as left" value of the parameter matches the "as-left" value specified in the surveillance test. Additionally, the "as-found" value must be in compliance with the Allowable Value specified in the TS.

4.5 SECY-11-0014 Discussion The Brunswick Plant relies on containment pressure higher than that present before the postulated design basis accident to provide net positive suction head (NPSH) margin for the pumps in the Emergency Core Cooling System (ECCS) and the containment heat removal system. In recent years, the use of containment accident pressure (CAP) to increase NPSH margin was challenged by the Advisory Committee on Reactor Safeguards (ACRS), by participants in the NRC hearing process, and by members of the public. The NRC Staff presented analyses and recommendations in SECY-11-0014 (i.e., Reference 7.7) that were subsequently adopted, in part, for use by the NRC Staff as guidance when reviewing applications relying on CAP. As part of pre-application meetings for this LAR, Duke Energy agreed to address the issues outlined in the SECY as part of the BSEP, Units 1 and 2 MELLLA+ License Amendment Request. Enclosure 11 of this submittal documents BSEP is in compliance with SECY-11-0014 guidance. Note that since this submittal does not increase reliance on CAP, the existing licensing basis for CAP and the existing methodology for demonstrating adequate NPSH with CAP is being retained.

5.0 Regulatory Analysis 5.1 Applicable Regulatory Requirements 10 CFR 50.36(c)(2)(ii), Criterion 2, requires TS Limiting Conditions for Operations (LCO) include process variables, design features, and operating restrictions that are initial conditions of design basis accident analysis. Compliance with TS ensures that system performance parameters are maintained within the values assumed in the safety analyses. The proposed OL and TS changes are supported by the safety analyses and continue to provide a level of protection comparable to the current TS. Applicable regulatory requirements and significant safety evaluations performed in support of the proposed changes are described iii the M+SAR.

Implementation of MELLLA+ does not require (1) an increase in the current maximum normal operating reactor dome pressure, (2) an increase in core power, (3) an increase in the maximum licensed core flow, (4) a change to source term methodology, (5) a new fuel product line, or (6) a change in fuel cycle length. As such, the impact on plant operation is minimal and, as demonstrated in the M+SAR, the MELLLA+ range expansion can be accomplished without exceeding any existing regulatory limits or design allowable limits applicable to BSEP.

BSEP 16-0056 Page 12of16 As part of MELLLA+ implementation for BSEP, Duke Energy will also implement the DSS-CD approach to automatically detect and suppress THI. Since the DSS-CD approach will continue to provide reliable, automatic detection and suppression of stability related power oscillations and provide protection against violation of the Safety Limit Minimum Critical Power Ratio for anticipated oscillations, compliance with GDC 10 and 12 of 10 CFR 50, Appendix A is maintained.

This request is not being submitted as a risk informed licensing action, as defined by Regulatory Guide (RG) 1.17 4 (i.e., Reference 7.6). However, it was evaluated from a risk perspective using the RG 1.174 criteria and, as demonstrated in Section 10.5, Individual Plant Evaluation, of the M+SAR, the net increase in core damage frequency (CDF) and large early release frequency (LERF) are both very small.

5.2 Precedence This application is being submitted using the following NRG-approved General Electric-Hitachi (GE-H) Licensing Topical Reports (L TR):

NEDC-33006P-A, (M+ L TR), Revision 3 and its associated safety evaluation report (i.e.,

Reference 7.2)

NEDC-33173P-A, (Methods L TR), Revision 4 and its associated safety evaluation report (i.e., Reference 7.3)

NEDC-33075P-A, (DSS-CD L TR), Revision 8 and its associated safety evaluation report (i.e., Reference 7.4)

The applicability of AREVA methods to the MELLLA+ operating domain is addressed in AREVA NP Report ANP-3108P, Applicability of AREVA BWR Methods to Brunswick Extended Power Flow Operating Domain (i.e., Reference 7.5). The AREVA computer codes, including AREVA's NRG-approved LTRs, are specified in Table 1-1a of the BSEP M+SAR (i.e., ).

Industry MELLLA+ Regulatory Experience:

March 28, -2014 - The NRC issued Amendment 180 to the Renewed Facility Operating License for the Monticello Nuclear Generating Plant allowing operation in the expanded MELLLA+

operating domain and changing the stability solution from Option Ill to DSS-CD (i.e., ADAMS Accession No. ML14035A248).

August 31, 2015 - The NRC issued Amendment 205 to the Facility Operating License for the Grand Gulf Nuclear Station allowing operation in the expanded MELLLA+ operating domain and changing the stability solution from Option Ill to DSS-CD (i.e., ADAMS Accession No. ML15229A219).

September 2, 2015 - The NRC issued Amendment 151 to the Facility Operating License for the Nine Mile Point Nuclear Station, Unit No. 2 allowing operation in the expanded"MELLLA+

operating domain, changing the stability solution from Option Ill to DSS-CD, and to increase the isotopic enrichment of boron-1 O in the sodium pentaborate solution utilized in the Standby Liquid Control System (i.e., ADAMS Accession No. ML15096A076).

BSEP 16-0056 Page 13 of 16 March 21. 2016 - The NRC issued Amendments 305 and 309 to the Renewed Facility Operating Licenses for the Peach Bottom Atomic Power Station, Units 2 and 3, allowing operation in the expanded MELLLA+ operating domain and changing the stability solution from Option Ill to DSS-CD (i.e., ADAMS Accession No. ML16034A372).

5.3 No Significant _Hazards Consideration Analysis In accordance with the requirements of 10 CFR 50.90, Duke Energy requests an amendment to Operating License DPR-71 and DPR-62 for the Brunswick Steam Electric Plant (BSEP), Units 1 and 2. This license amendment request proposes revisions to the BSEP Operating License (OL) and Technical Specifications {TS) to allow operating in the expanded Maximum Extended Load Line Analysis Plus (MELLLA+) domain. Duke Energy has evaluated whether or not a significant hazards consideration is involved with the proposed changes in accordance with the standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

1.

Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The proposed operation in the MELLLA+ operating domain does not significantly increase the probability or consequences of an accident previously evaluated. The probability (i.e., frequency of occurrence) of Design Basis Accidents (DBAs) occurring is not affected by the MELLLA+ operating domain because BSEP continues to comply with the regulatory and design basis criteria established for plant equipment. Furthermore, a probabilistic risk assessment demonstrates that the calculated core damage frequencies do not significantly change due to the MELLLA+.

There is no change in consequences of postulated accidents when operating in the MELLLA+ operating domain compared to the operating domain previously evaluated.

The results of accident evaluations remain within the NRC approved acceptance limits.

The spectrum of postulated transients has been investigated and is shown to meet the plant's currently licensed regulatory criteria. Continued compliance with the Safety Limit Minimum Critical Power Ratio (SLMCPR) will be confirmed on a cycle-specific basis consistent with the criteria accepted by the NRC.

Challenges to the reactor coolant pressure boundary were evaluated for the MELLLA+

operating domain conditions (i.e., pressure, temperature, flow, and radiation) and were found to meet their respective acceptance criteria for allowable stresses and overpressure margin.

Challenges to the containment were evaluated and the containment and its associated cooling systems continue to meet the current licensing basis. The calculated post-Loss of Coolant Accident (LOCA) suppression pool temperature remains acceptable.

The proposed changes to the sodium pentaborate (SPB) enrichment and volume requirements maintain the capability of the Standby Liquid Control (SLC) system to perform this reactivity control function and ensure continued compliance with the requirements of 1 O CFR 50.62. The SLC system is not considered to be an initiator of

BSEP 16-0056 Page 14of16 any event. The use of the proposed SPB solution with a higher boron-10 (B-10) isotope enrichment does not alter the design, function, or operation of the SLC system or increase the likelihood of malfunction that could increase the consequences of an accident.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2.

Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No The proposed operation in the MELLLA+ operating domain does not create the possibility of a new or different kind of accident from any previously evaluated.

Equipment that could be affected by the MELLLA+ operating domain has been evaluated. No new operating mode, safety-related equipment lineup, accident scenario, or equipment failure mode was identified. The full spectrum of accident considerations has been evaluated and no new or different kind of accident was identified. The MELLLA+ operating domain uses developed technology, and applies it within the capabilities of existing plant safety-related equipment in accordance with the regulatory criteria, including NRG-approved codes, standards and methods. The use of the proposed SPB solution with a higher B-10 isotope enrichment does not alter the design, function, or operation of the SLC system or create the possibility of a new or different kind of accident. The proposed changes have been assessed and determined not to introduce a different accident than that previously evaluated. No new accident or event precursor has been identified.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

3.

Does the proposed amendment involve a significant reduction in a margin of safety?

Response: No The proposed operation in the MELLLA+ domain does not involve a significant reduction in the margin of safety.

The MELLLA+ operating domain can only affect design and operational margins.

Challenges to the fuel, reactor coolant pressure boundary, and containment were evaluated for the MELLLA+ operating domain conditions. Fuel integrity is maintained by meeting existing design and regulatory limits. The calculated loads on affected structures, systems, and components, including the reactor coolant pressure boundary, will remain within their design allowables for design basis event categories. No NRC acceptance criterion is exceeded. The BSEP configuration and responses to transients and postulated accidents do not result in exceeding the presently approved NRC acceptance limits, thereby preserving safety margins.

BSEP 16-0056 Page 15of16 The proposed changes to the SPB enrichment and volume requirements ensure SLC system shutdown margins and post-accident pH control margins are maintained while maintaining compliance with the requirements of 1 O CFR 50.62.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above analysis, Duke Energy concludes that the proposed amendment presents no significant hazards consideration under the standards setforth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

6.0 Environmental Considerations The environmental effects of MELLLA+ operating domain expansion are controlled at the same limits as the current analyses. None of the present limits for plant environmental releases are increased as a consequence of MELLLA+ operating domain expansion. MELLLA+ has no effect on the non-radiological elements of concern, and the plant will be operated in an environmentally acceptable manner as documented by the Environmental Assessment for BSEP's current licensed operating domain. Existing Federal, State and local regulatory permits presently in effect accommodate the MELLLA+ operating domain expansion without modification.

The evaluation of the effects of MELLLA+ operating domain expansion on normal radiological effluents is included in Section 8.0 of the M+SAR. There will be no change in the radiological effluents released to the environment due to the MELLLA+ operating domain expansion. The normal effluents and doses remain well within the 10 CFR 20 limits and the 10 CFR 50, Appendix I guidance. There is no change to the predicted doses from postulated accidents and the 10 CFR 50.67 dose criteria continue to be met. In addition, the quantity of spent fuel does not increase as a result of MELLLA+ operating domain expansion.

Duke Energy has determined that operation with the proposed MELLLA+ license amendment does not involve: (i) a significant hazards consideration, (ii) a significant change in the types or a significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed license amendment meets the eligibility criterion for categorical exclusion as set forth in 10 CFR 51.22(c)(9).

Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed license amendment.

7.0 References

1. Letter from the U.S. Nuclear Regulatory Commission to Mr. John S. Keenan, "Issuance of Amendment Re: Extended Power Uprate," dated May 31, 2002, ADAMS Accession Number ML021430551.

2. GE Nuclear Energy Report NEDC-33006P-A, Maximum Extended Load Line Limit Analysis Plus Licensing Topical Report, Revision 3, dated June 2009.

3. GE-Hitachi Nuclear Energy Report NEDC-33173P-A, Applicability of GE Methods to Expanded Operating Domains Licensing Topical Report, Revision 4, dated November 2012.

BSEP 16-0056 Page 16of16

4. GE-Hitachi Nuclear Energy Report NEDC-33075P-A, Detect And Suppress Solution -

Confirmation Density Licensing Topical Report, Revision 8, dated November 2013.

5. AREVA NP Report, ANP-3108P, Applicability of AREVA NP BWR Methods to Brunswick Extended Power Flow Operating Domain, Revision 1, July 2015.

6. Regulatory Guide 1.17 4, An Approach for Using Probabilistic Risk Assessment in Risk Informed Decisions on Plant-Specific Changes to the Licensing Basis, Revision 2, May 2011.

7. NRC Policy Issue SECY-11-0014, Use of Containment Accident Pressure in Analyzing Emergency Core Cooling System and Containment Heat Removal System Pump Performance in Postulated Accidents, January 31, 2011.

Brunswick Unit 1 Technical Specification and Operating License Appendix B Mark-ups BSEP 16-0056

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SR 3.1.7.6 SR 3.1.7.7 SR 3.1.7.8 Brunswick Unit 1 SURVEILLANCE FREQUENCY Verify each pump develops a flow rate 2': 41.2 gpm at a In accordance with discharge pressure 2': 1190 psig.

the lnservice Testing Program Verify flow through one SLC subsystem from pump into reactor pressure vessel.

Verify sodium pentaborate enrichment is 2': 47 atom percent B-10.

):-,

f 92 -~

3.1-22 24 months on a STAGGERED TEST BASIS Prior to addition to SLC tank Amendment No. 227

Q) -

ca z...

0 0

.c I-ca c:i: 'E 0:::

Q) 1-z E w :::s u *-

z "C 0

0 u!

c:

~ 9 Q)

Brunswick Unit 1 NET VOLUME OF SOLUTION IN TANK Figure 3.1. 7-1 (page 1 of 1)

Sodium Pentaborate Solution Volume Versus Concentration Requirements 3.1-23 SLC System 3.1.7 Amendment No. 227

'§ 10.5

.2 0

(/)

.~ 10.0 Q) -

m z-Q.8

~~

et:'. -

9.5 I-a.

ZE

~.:!

z-o 0 g 9.0

(.).,

c:

Q) u -

Cl) a.

8.5

~

Cl

"(ij New TS Figure 3.1.7-1 I Note: B-10Atomic Enrichment~ 92% I I Acceptable I 8.0.............................. _...__,..........,--..--~.................... ----.-..........,._.,..._.,........-.-....,_--.-....................,,.._.,......_...,..-.....,..._.....,....--.-__ __,~

800 1200 1600 2000 2400 2800 NETVOLUME OF SOLUTION IN TANK (gallons) 3200

ACTIONS (continued)

F.

G.

H.

h th CONDITION As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

As Fe~l:liFeEI ey Re~l:liFeEI

,A,etieA Q.1 aAEI FefeFeAeeEI iA Taele a.a.1.1 1.

Re~l:liFeEI AetieA aAEI asseeiateEI GeFR13letieA TiFRe ef GeAElitieA I Aet FRet.

See Insert A for changes to Actions I and J and new Condition K Brunswick Unit 1 F.1 G.1 H.1 H

J4 REQUIRED ACTION Be in MODE 2.

Be in MODE 3.

Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

IAitiate alteFAate FRett:ieEI te Eleteet aAEI s1:11313Fess tt:ieFFRal t:iyElm1:1lie iAstaeility eseillatieAs.

ReEl1:1ee Tl=IERMAb POWER te < 20% RTP.

3.3-3 RPS Instrumentation 3.3.1.1 COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours Immediately 12 A91:1FS 4 A91:1FS Amendment No. 217 I

jlnsert A I I.

As required by Required Action J.

D. l and referenced in Tabl e 3. 3. 1. 1 - 1.

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

K.

Required Action and associated Comoletion Time of Condition J not met.

I. l AND I. 2 AND I. 3 J. 1 AND J. 2 AND Initiate action to implement the Ma nual BSP Regio n s defined in the COLR.

Implement the Automated BSP Scr am Regi on using the modified APRM Simulated Thermal Power -

High scram setpoints defined in the COLR.

Initiate action in accordance with Specification 5. 6. 7.

Initiate action to implement the Manual BSP Regions defined in the COLR.

Reduce operation to below the BSP Boundary defined in the COLR.

J. 3

NOTE---------

K. 1 LCO 3. 0.4 is not applicable Restore required channel to OPERABLE.

Reduce THERMAL POWER to less than 18 RTP.

Immediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately Immediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 120 days 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS continued SR d.d.1.1.19 Brunswick Unit 1 SURVEILLANCE FREQUENCY Verify OPRM is not bypassed when APRM Simulated 24 months Thermal Power is ~ 25% and recirculation drive ~ow is

~ ~

3.3-8 Amendment No. 217 I

FUNCTION

1.

Intermediate Range Monitors

a.

Neutron Flux-High

b.

lnop

2.

Average Power Range Monitors

a.

Neutron Flux-High (Setdown)

b.

Simulated Thermal Power-High Table 3.3.1.1-1 (page 1 of 3)

Reactor Protection System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS 2

REQUIRED CHANNELS PER TRIP SYSTEM 3

3 CONDITIONS REFERENCED FROM REQUIRED ACTION D.1 G

H G

F RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SR 3.3.1.1.2 SR 3.3.1.1.4 SR 3.3.1 1.5 SR 3.3.1.1.6 SR 3.3.1.1.7 SR 3.3 11 13 SR 3 3 1 1 15 SR 3.3.1.1.2 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.4 SR 3.3 1.1.5 SR 3.3.1.1.15 SR 3.31.1.4 SR 3.3.1.1.5 SR 3.3.1.1.15 SR 3 3.11.2 SR 3 3.1.1.5 SR 3.3.1.1.7 SR 3.3.11.8 SR 3 3.1.1.11 SR 3.3.11.13 SR 3.3.1.1.2 SR 3.3.11.3 SR 3.3.1.1.5 SR 3 3.11.8 SR 33.11.11 SR 3.3.1.1.13 SR 3.3.1.1.18 ALLOWABLE VALUE s 120/125 divisions of full scale s 120/125 divisions of full scale NA NA s 22.7% RTP (continued)

~ 0.61W + 65.2% RTP (b)(e) F--------

(a)

With any control rod withdrawn from a core cell containing one or more fuel assemblies (b) s (0.55 (W -1!.W) + 62 6% RTP] when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating." The value of l!.W is defined in plant procedures.

(c)

Each APRM channel provides inputs to both trip systems.

Brunswick Unit 1 3.3-9 Amendment No. 222

(f) Following DSS-CD implementation, DSS-CD is not required to be armed while in the DSS-CD Armed Region during the first reactor startup and during the first controlled shutdown that passes completely through the DSS-CD Armed Region. However, DSS-CD is considered OPERABLE and shall be maintained OPERABLE and capable of automatically arming for operation at recirculation drive flow rates above the DSS-CD Armed Region.

Recirculation Loops Operating 3.4.1 3.4 REACTOR COOLANT SYSTEM (RCS)

,,....,..,.....,.....,.~.....,..._,.............. w"'"""'..,...,....,....,.....,.....,.....,.~..............._,....,,.......................,...._

3.4.1 Recirculation Loops Operating the plant is not operating in the MELLLA+

operating domain, as defined in the COLR, and provided LCO 3.4.1 APPLICABILITY:

ACTIONS Two recirculation loops with matched flows shall b in operation, One recirculation loop may be in operation provided the following limits are applied when the associated LCO is applicable:

a.

LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," single loop operation limits specified in the COLR;

b.

LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," single loop operation limits specified in the COLR;

c.

LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," single loop operation limits specified in the COLR; and

d.

LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation,"

Function 2.b (Average Power Range Monitors Simulated Thermal Power-High), Allowable Value of Table 3.3.1.1-1 is reset for single loop operation.

MODES 1 and 2.

CONDITION REQUIRED ACTION COMPLETION TIME A.

Requirements of the LCO not met.

Brunswick Unit 1 A.1 Satisfy the requirements of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months the LCO.

(continued) 3.4-1 Amendment No. 246 I

Recirculation Loops Operating 3.4.1 ACTIONS continued CONDITION REQUIRED ACTION Required Action and associated Completion Time of Condition A not met.

&.+

Be in MODE 3.

\\a OR B No recirculation loops in operation.

SURVEILLANCE REQUIREMENTS SR 3.4.1.1 SURVEILLANCE

N 0 TE-----------------------------

N o t required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both recirculation loops are in operation.

Verify recirculation loop jet pump flow mismatch with both recirculation loops in operation:

a.

~ 10% of rated core flow when operating at

< 75% of rated core flow; and

b.

~ 5% of rated core flow when operating at 2". 75% of rated core flow.

COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

8. Operation in the MELLLA+

domain with a single recirculation loop in operation.

8.1 Initiate action to exit Immediately the MELLLA+ operating domain.

Brunswick Unit 1 3.4-2 Amendment No. 244

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.5 CORE OPERATING LIMITS REPORT (COLR)

a.

Core operating limits shall be established prior to each reload cycle, or prior to any remaining portion of a reload cycle, and shall be documented in the COLR for the following:

1.

The AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) for Specification 3.2.1;

2.

The MINIMUM CRITICAL POWER RATIO (MCPR) for Specification 3.2.2;

3.

The LINEAR HEAT GENERATION RATE (LHGR) for Specification 3.2.3;

4.

The period based detestion algorithRl (PBD/\\) setpoint for runstion 2.f, Ossillation Power Range Monitor (OPRM) Upssale, for epesifisation a.a.1.1; and

5.

The Allo able Values and power range setpoints for Rod Block Monitor scale Functions for Specification 3.3.2.1.

b.

The analytical me hods used to determine the core operating limits shall be those previous reviewed and approved by the NRC, specifically those described in the following documents:

1.

NEDE-24011-P-A, "General Electric Standard Application for Reactor Fu."

2.

XN-NF-81-5 (P)(A), RODEX2 Fuel Rod Thermal-Mechanical Response E luation Model.

3.

)(A), Generic Mechanical Design for Exxon Nuclear Jet P mp BWR Reload Fuel.

4.

EMF-85-74(P) upplement 1(P)(A) and Supplement 2(P)(A),

RODEX2A (B R) Fuel Rod Thermal-Mechanical Evaluation Model.

5.

ANF-89-98(P)(A, Generic Mechanical Design Criteria for BWR Fuel Designs.

(c n n The Manual Backup Stability Protection (BSP) Scram Region (Region I), the Manual BSP Controlled Entry Region (Region II), the modified APRM Simulated Thermal Power - High scram setpoints used in the Automated BSP Scram Region, the BSP Boundary for Specification 3.3. 1.1, and Brunswick Unit 1 5.0-20 Amendment No. 246 I

1_

NEDC-33075P-A, GE Hitachi Boiling Water Reactor, Detect and Suppress Solution - Confirmation Density, Revision 8, November 2013.

Reporting Requirements 5.6 5.6 Repo ~ ing Requirements (continued}

5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued}

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.

17.

18.

\\V Brunswick Unit 1 XN-NF-80-19(P}(A} Volume 1, Exxon Nuclear Methodology for Boiling Water Reactors - Neutronic Methods for Design and Analysis.

XN-NF-80-19(P}(A} Volume 4, Exxon Nuclear Methodology for Boiling Water Reactors: Application of the ENC Methodology to BWR Reloads.

EMF-2158(P)(A}, Siemens Power Corporation Methodology for Boiling Water Reactors: Evaluation and Validation of CASM0-4/MICROBURN-82.

XN-NF-80-19(P}(A) Volume 3, Exxon Nuclear Methodology for Boiling Water Reactors, THERMEX: Thermal Limits Methodology Summary Description.

XN-NF-84-105(P)(A} Volume 1, XCOBRA-T: A Computer Code for BWR Transient Thermal-Hydraulic Core Analysis.

ANP-10307PA, AREVA MCPR Safety Limit Methodology for Boiling Water Reactors, Revision 0, June 2011.

ANF-913(P}(A) Volume 1, COTRANSA2: A Computer Program for Boiling Water Reactor Transient Analyses.

ANF-1358(P)(A), The Loss of Feedwater Heating Transient in Boiling Water Reactors.

EMF-2209(P}(A), SPCB Critical Power Correlation.

EMF-2245(P}(A), Application of Siemens Power Corporation's Critical Power Correlations to Co-Resident Fuel.

EMF-2361 (P)(A), EXEM BWR-2000 ECCS Evaluation Model.

EMF-2292(P)(A}, ATRIUM'-10: Appendix K Spray Heat Transfer Coefficients.

EMF-CC-074(P}(A) Volume 4, BWR Stability Analysis -

Assessment of STAIF with Input from MICROBURN-82.

NEDO 3246§ A, Reaotor Stability Detest and Suppress Solutions Licensing Basis Methodology for Reload Apptisations.

{continued) 5.0-21 Amendment No. 262

5.6 Reporting Requirements (continued)

Reporting Requirements 5.6 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

20.

BAW-10247PA, Realistic Thermal-Mechanical Fuel Rod Methodology for Boiling Water Reactors, Revision 0, April 2008.

21.

ANP-10298P-A, ACE/ATRIUM 10XM Critical Power Correlation, Revision 1, March 2014.

c.

The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SOM, transient analysis limits, and accident analysis limits) of the safety analysis are met.

d.

The COLR, including any midcycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.

5.6.6 Post Accident Monitoring (PAM) Instrumentation Report When a report is required by Condition B or F of LCO 3.3.3.1, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.7 Oscillation Power Range Monitor (OPRM) Report When a report is required by Condition I of LCO 3.3.1.1, "RPS Instrumentation,"

a report shall be submitted within the following 90 days. The report shall outline the preplanned means to provide backup stability protection, the cause of the

~

inoperability, and the plans and schedule for restoring the required instrumentation channels to OPERABLE status.

~'-->...>-"-~

"-..). "->.._"-..). >....A.A.>

.-..~

A.."-..J.

_A->

Brunswick Unit 1 5.0-22 Amendment No. 269 I

Amendment Number 262 Brunswick Unit 1 AddWonalCondWons The fuel channel bow standard deviation component of the channel bow model uncertainty used by ANP-10307PA, AREVA MCPR Safety Limit Methodology for Boiling Water Reactors (i.e., TS 5.6.5.b.11) to determine the Safety Limit Minimum Critical Power Ratio shall be increased by the ratio of channel fluence gradient to the nearest channel fluence gradient bound of the channel measurement database, when applied to channels with fluence gradients outside the bounds of the measurement database from which the model uncertainty is determined.

The licensee shall not operate the facility within the MELLLA+ operating domain with Feedwater Temperature Reduction (FWTR), as defined in the Core Operating Limits Report.

App. B-2 Implementation Date Upon implementation of Amendment No. 262.

Upon implementation of Amendment No. XXX.

Amendment No. 269

Brunswick Unit 2 Technical Specification and Operating License Appendix B Mark-ups BSEP 16-0056

SLC System 3.1.7 SURVEILLANCE REQUIREMENTS (continued)

SR 3.1.7.6 SR 3.1.7.7 SR 3.1.7.8 Brunswick Unit 2 SURVEILLANCE FREQUENCY Verify each pump develops a flow rate ~ 41.2 gpm at a In accordance with discharge pressure ~ 1190 psig the lnservice Testing Program Verify flow through one SLC subsystem from pump into reactor pressure vessel Verify sodium pentaborate enrichment is~ 47 atom percentB-10.

)\\

3.1-22 24 months on a STAGGERED TEST BASIS Prior to addition to SLC tank Amendment No. 255 I

Q) 0 -

ctJ z

~

0 0

.c

~ ctJ

<( c:

Q:'.

Q)

~

z E w :I u *-

z "C 0

0 u~

c:

Q)

~

Q)

Brunswick Unit 2 SLC System 3.1.7 Replace w/NEW Graph 2400 2600 2800 3000 NET VOLUME OF SOLUTION IN TANK (gallons)

Figure 3.1.7-1(page1of1)

Sodium Pentaborate Solution Volume Versus Concentration Requirements 3.1-23 Amendment No. 255 I

11.0

~ 10.5

J 0

Ul

.!: 10.0

~

10 z~

Q_g

~.fl 0:: ;

9.5 I-c..

ZE

~.:!

z-c 0

~ 9.0 u_

c

~

(.)

Q; c.. -

8.5

..c Cl

a; New TS Figure 3.1.7-1 I Note: B-10 Atomic Enrichment~ 92% I I Acceptable I 8.0 -l"--.--'........... -r--r..._r--"-,.---+--.--"""r--'1---................ --.--.,...........--.-......... --.------.--..----.----.-........... _..,..'--1 800 1200 1600 2000 2400 2800 NET VOLUME OF SOLUTION IN TANK (gallons) 3200

A CTIONS (continued)

CONDITION F.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

G.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

H.

As required by Required Action D.1 and referenced in Table 3.3.1.1-1.

h As FeeiuiFeEl sy ~eeiuiFeEl AstiaR t:l.1 aREl FefeFeRseEl iR Tasle 3.3.1.1 1.

J.:-

ReeiuiFeEl AstiaR aREl assasiateEl GaA=113letiaR Tiffie a~ GaRElitiaR I Rat A'let See Insert A for changes to Actions I and J and new Condition K Brunswick Unit 2 F.1 G.1 H.1 h+

J.4 REQUIRED ACTION Be in MODE 2.

Be in MODE 3.

Initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies.

IRitiate alteFRate A'!eU::iaEl ta Eletest aREl su1313Fess thmA'lal hyElmulis iRstasility assillatiaRs.

~eEluse Tl=H~~MAb POW~~ ta < 20% RTP.

3.3-3 RPS Instrumentation 3.3.1.1 COMPLETION TIME 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 12 hours Immediately 12 haUFS 4 hauFs Amendment No. 243 I

I Insert A I I.

As required by Required Action J.

D. 1 and referenced in Table 3. 3. 1. 1 - 1.

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

K.

Required Action and associated Completi o n Time o f Condition J not met.

I. l AND I. 2 AND I. 3 J.l AND J. 2 AND Initiate action to implement the Manual BSP Regions defined in the COLR.

Implement the Automated BSP Scram Region using the modified APRM Simulated Thermal Power -

Hi gh s c r arr setpo ints defined in the COLR.

Initiate action in accordance with Specification 5. 6.7.

Initiate action to implement the Manual BSP Regions defined in the COLR.

Reduce opera t i on to below the BSP Boundary defined in the COLR.

J.3

NOTE---------

K. l LCO 3. 0. 4 is no t applicable Restore required channel to OPERABLE.

Reduce THERMAL POWER to less than 18 RTP.

Immediately 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Immediately Immediately 12 hou r s 120 days 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

SURVEILLANCE REQUIREMENTS continued SR a.a.1.1.10 Brunswick Unit 2 SURVEILLANCE Thermal Power is ~ 25% and resirsulation dri';e flow is

<eo%.

3.3-8 RPS Instrumentation 3.3.1.1 FREQUENCY Amendment No. 243 I

FUNCTION

1.

Intermediate Range Monitors

a.

Neutron Flux-High

b.

lnop

2.

Average Power Range Monitors a

Neutron Flux-High (Setdown) b Simulated Thermal Power-High Table3.3.1.1-1 (page1 of3)

Reactor Protection System Instrumentation APPLICABLE MODES OR OTHER SPECIFIED CONDITIONS 2

REQUIRED CHANNELS PER TRIP SYSTEM CONDITIONS REFERENCED FROM REQUIRED ACTION D.1 G

H G

F RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS SR 3.3.1.1.2 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.6 SR 3.3.11 7 SR 3.3.1.113 SR 3 3 1 1 15 SR 3.3.1.1.2 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.13 SR 3.3.1.1.15 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1.15 SR 3.3.1.1.4 SR 3.3.1.1.5 SR 3.3.1.1 15 SR 3.3.1.1.2 SR 3.3.1.1.5 SR 3.3.1.1.7 SR 3.3.1.1.8 SR 33.1.1.11 SR 3.3.1 1.13 SR 3.3.1.1.2 SR 3.3.1.1.3 SR 3.3.1.1.5 SR 3.3.1.1.B SR 3.3.11.11 SR 3.3.1.1.13 SR 3.3.1.1.18 ALLOWABLE VALUE s 1201125 divisions of full scale s 1201125 divisions of full scale NA NA s 22 7% RTP

.. Q.titi1N I 62.61' R'FP" nd s 0.61 W + 65.2% RTP(b) (e)

(continued)

(a)

With any control rod withdrawn from a core cell containing one or more fuel assemblies (b) s (0.55 (W - liW) + 62.6% RTP) when reset for single loop operation per LCO 3.4.1, "Recirculation Loops Operating." The value of liW is defined in plant procedures.

(c)

Each APRM channel provides inputs to both trip systems.

(e) With OPRM Upscale (Function 2.f) inoperable, the Automated BSP Scram Region setpoints are implemented in accordance with Action I of this Specification.

Brunswick Unit 2 3.3-9 Amendment No. 247

RPS Instrumentation 3.3.1.1 Table 3.3.1.1*1(page2 of 3)

Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED OTHER CHANNELS FROM SPECIFIED PER TRIP REQUIRED SURVEILLANCE ALLOWABLE FUNCTION CONDITIONS SYSTEM ACTIOND.1 REQUIREMENTS VALUE

2.

Average Power Range Monitors (continued)

c.

Neutron Flux-High 3 (c)

F SR 3.3.1.1.2 s 118.7% RTP SR 3.3.1.1.3 SR 3.3.1.1.5 SR 3.3.1.1.8 SR 3311.11 SR331113

d.

lnop 1,2 3 (C:)

G SR 3.3.1.1.5 NA SR 3.3.1.1.11

e.

2-0ut-Of-4 Voter 1,2 G

SR 3.3.1.1.2 NA SR 33.1.1.5 SR 3.3.1.1.11

~

SR 3.3.1.1.15 SR 331.1.17 OPRM Upscale

,, ~

3<c:l SR 3.3.1.1.2 NAI" SR 3.3.1.1.5

~

SR 3 31.1.8 SR 3 31.1.11 SR 3.3.1.1.13 SR 3.3.1.1.18 SR U.1.1.19 3

Reactor Vessel Steam Dome Pressure-1,2 2

G SR 3.31.1.2 s 1077 psig High SR 3.31.1.5 SR 3.31.1.9 SR 3.31.1.10 SR 3.3.1.1.13 SR 3.31.1.15 SR 3.31.1.17

4.

Reactor Vessel Water Level-Low Level 1 1,2 G

SR 33.1.1.2

~ 153 inches SR 3.3.11.5 SR 3.3.1.1.9 SR 33.1.1.10 SR 3.3.1.1.13 SR 33.1.115 SR 33.1.1.17

5.

Main Steam Isolation Valve-Closure 8

F SR 3.31.1.5 s 10% closed SR 3.3.1.1.9 SR 3.3.1.1.13 SR 3.31.1.15 SR 3.3.1.1.17 6

Drywell Pressure-High 1,2 G

SR 3.3 1.12 s 18psig SR 3.31 1 5 SR 3.31.1.9 SR 3.31.110 SR 3.31 1 13 SR 3.31.115 (continued)

Confirmation Density (c)

Each APRM channel provides inputs to both trip systems.

Algorithm (CDA) setpoints.

(d)

See COLR for OPRM Brunswick Unit 2 3.3-10 Amendment No. 243 See Insert B for new footnote (f)

(f) Following DSS-CD implementation, DSS-CD is not required to be armed while in the DSS-CD Armed Region during the first reactor startup and during the first controlled shutdown that passes completely through the DSS-CD Armed Region. However, DSS-CD is considered OPERABLE and shall be maintained OPERABLE and capable of automatically arming for operation at recirculation drive flow rates above the DSS-CD Armed Region.

Recirculation Loops Operating 3.4.1 3.4 REACTOR COOLANT SYSTEM (RCS) the plant is not operating in the MELLLA+

operating domain, as defined in the COLR, and provided 3.4.1 Recirculation Loops Operating LCO 3.4.1 APPLICABILITY:

ACTIONS Two recirculation loops with matched flows shall b in operation, One recirculation loop may be in operation provided the following limits are applied when the associated LCO is applicable:

a.

LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," single loop operation limits specified in the COLR;

b.

LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," single loop operation limits specified in the COLR;

c.

LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," single loop operation limits specified in the COLR; and

d.

LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation,"

Function 2.b (Average Power Range Monitors Simulated Thermal Power-High), Allowable Value of Table 3.3.1.1-1 is reset for single loop operation.

MODES 1 and 2.

CONDITION REQUIRED ACTION COMPLETION TIME A.

Requirements of the LCO not met.

Brunswick Unit 2 A. 1 Satisfy the requirements of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months the LCO.

(continued) 3.4-1 Amendment No. 27 4

Recirculation Loops Operating 3.4.1 ACTIONS continued B.

J CONDITION Required Action and associated Completion Time of Condition A not met.

OR a No recirculation loops in operation.

SURVEILLANCE REQUIREMENTS REQUIRED ACTION S:-+

Be in MODE 3.

~

SURVEILLANCE COMPLETION TIME 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months FREQUENCY SR 3.4.1.1

N 0 TE------------------------------

N o t required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both recirculation loops are in operation Verify recirculation loop jet pump flow mismatch with both recirculation loops in operation:

a.

$ 10% of rated core flow when operating at

< 75% of rated core flow; and

b.

$ 5% of rated core flow when operating at

75% of rated core flow.

B. Operation in the MELLLA+

domain with a single recirculation loop in operation.

B.1 Initiate action to exit the MELLLA+ operating domain.

Brunswick Unit 2 3.4-2 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Immediately Amendment No. 272 I

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.5 CORE OPERATING LIMITS REPORT (COLR)

a.

Core operating limits shall be established prior to each reload cycle, or prior to any remaining portion of a reload cycle, and shall be documented in the COLR for the following:

1.

The AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) for Specification 3.2.1;

2.

The MINIMUM CRITICAL POWER RATIO (MCPR) for Specification 3.2.2;

3.

The LINEAR HEAT GENERATION RATE (LHGR) for Specification 3.2.3;

4.

The period based deteotion algorithm (PBDA) setpoint for Funotion 2.f, Osoillation Power Range Monitor (OPRM) Upsoale, for apeoifioation 3.3.1.1; and

5.

The Allowable Values and power range setpoints for Rod Block Monitor Upscale Functions for Specification 3.3.2.1.

b.

The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:

Brunswick Unit 2

1.

NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel."

2.

XN-NF-81-58(P)(A), RODEX2 Fuel Rod Thermal-Mechanical Response Evaluation Model.

3.

XN-NF-85-67(P)(A), Generic Mechanical Design for Exxon Nuclear Jet Pump BWR Reload Fuel.

4.

EMF-85-74(P) Supplement 1(P)(A) and Supplement 2(P)(A),

RODEX2A (BWR) Fuel Rod Thermal-Mechanical Evaluation Model.

5.

ANF-89-98(P)(A), Generic Mechanical Design Criteria for BWR Fuel Designs.

(continued) 5.0-20 Amendment No. 274

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

Brunswick Unit 2

6.

XN-NF-80-19(P)(A) Volume 1, Exxon Nuclear Methodology for Boiling Water Reactors - Neutronic Methods for Design and Analysis.

7.

XN-NF-80-19(P)(A) Volume 4, Exxon Nuclear Methodology for Boiling Water Reactors: Application of the ENC Methodology to BWR Reloads.

8.

9.

10.

11.

12.

13.

14.

15.

EMF-2158(P)(A), Siemens Power Corporation Methodology for Boiling Water Reactors: Evaluation and Validation of CASM0-4/MICROBURN-B2.

XN-NF-80-19(P)(A) Volume 3, Exxon Nuclear Methodology for Boiling Water Reactors, THERMEX: Thermal Limits Methodology Summary Description.

XN-NF-84-105(P)(A) Volume 1, XCOBRA-T: A Computer Code for BWR Transient Thermal-Hydraulic Core Analysis.

ANP-10307PA, AREVA MCPR Safety Limit Methodology for Boiling Water Reactors, Revision 0, June 2011.

ANF-913(P)(A) Volume 1, COTRANSA2: A Computer Program for Boiling Water Reactor Transient Analyses.

ANF-1358(P)(A), The Loss of Feedwater Heating Transient in Boiling Water Reactors.

EMF-2209(P)(A), SPCB Critical Power Correlation.

EMF-2245(P)(A), Application of Siemens Power Corporation's Critical Power Correlations to Co-Resident Fuel.

16.

EMF-2361(P)(A), EXEM BWR-2000 ECCS Evaluation Model.

17.

EMF-2292(P)(A), ATRIUM'-10: Appendix K Spray Heat Transfer Coefficients.

18.

EMF-CC-074(P)(A) Volume 4, BWR Stability Analysis -

Assessment of STAIF with Input from MICROBURN-B2.

49-:-

~H:oo 32465 A, Reaotor gtability Detest and guppress golutions Lioensing Basis Methodology for Reload f>.pplioations.

(continued) 5.0-21 Amendment No. 290

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.5 CORE OPERATING LIMITS REPORT (COLR) (continued)

20.

BAW-10247PA, Realistic Thermal-Mechanical Fuel Rod Methodology for Boiling Water Reactors, Revision 0, April 2008.

21.

ANP-10298P-A, ACE/ATRIUM 10XM Critical Power Correlation, Revision 1, March 2014.

c.

The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SOM, transient analysis limits, and accident analysis limits) of the safety analysis are met.

d.

The COLR, including any midcycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.

5.6.6 Post Accident Monitoring (PAM) Instrumentation Report When a report is required by Condition B or F of LCO 3.3.3.1, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.7 Oscillation Power Range Monitor (OPRM) Report When a report is required by Condition I of LCO 3.3.1.1, "RPS Instrumentation,"

a report shall be submitted within the following 90 days. The report shall outline the preplanned means to provide backup stability protection, the cause of the inoperability, and the plans and schedule for restoring the required instrumentation channels to OPERABLE status.

Brunswick Unit 2 5.0-22 Amendment No. 297

Amendment Number 276 290 Additional Conditions Upon implementation of Amendment No. 276 adopting TSTF-448, Revision 3, the determination of control room envelope (CRE) unfiltered air inleakage as required by SR 3.7.3.3, in accordance with TS 5.5.13.c.(i), the assessment of CRE habitability as required by Specification 5.5.13.c.(ii),

and the measurement of CRE pressure as required by Specification 5.5.13.d, shall be considered met.

Following implementation:

(a)

The first performance of SR 3.7.3.3, in accordance with Specification 5.5.13.c.(i),

shall be within the specified Frequency of 6 years, plus the 18-month allowance of SR 3.0.2, as measured from June 11, 2004, the date of the most recent successful tracer gas test.

(b)

The first performance of the periodic assessment of CRE habitability, Specification 5.5.13.c.(ii), shall be within the next 9 months.

(c)

The first performance of the periodic measurement of CRE pressure, Specification 5.5.13.d, shall be within 18 months, plus the 138 days allowed by SR 3.0.2, as measured from the date of the most recent successful pressure measurement test.

The fuel channel bow standard deviation component of the channel bow model uncertainty used by ANP-10307PA, AREVA MCPR Safety Limit Methodology for Boiling Water Reactors (i.e.,

TS 5.6.5.b.11) to determine the Safety Limit Minimum Critical Power Ratio shall be increased by the ratio of channel fluence gradient to the nearest channel fluence gradient bound of the channel measurement database, when applied to channels with fluence gradients outside the bounds of the measurement database from which the model uncertainty is determined.

XXX The licensee shall not operate the facility within the MELLLA+ operating domain with Feedwater Temperature Reduction (FWTR), as defined in the Core Operating Limits Report.

Brunswick Unit 2 App. B-2 Implementation Date As described in paragraphs (a), (b),

and (c) of this Additional Condition.

Upon implementation of Amendment No. 290 Upon implementation of Amendment No. XXX.

Amendment No. 297

BSEP 16-0056 Brunswick Unit 1 Technical Specification Bases Mark-ups (For Information Only)

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE Average Power Range Monitor (APRM) (continued)

SAFETY ANALYSES, LCO, and four OPRM "cells," forming a total of 24 separate OPRM cells per APRM APPLICABILITY channel, each with either three or four detectors. LPRMs near the edge of the core are assigned to either one or two OPRM cells. /\\ minimum of 18 OPRM cells in an /\\PRM channel must have at least two OPE:RABU:

LPRMs for the OPRM Upscale Function 2.f to be OPE:RABU: (Ref. 22).

2.a. Average Power Range Monitor Neutron Flux-High (Setdown)

For operation at low power (i.e., MODE 2), the Average Power Range Monitor Neutron Flux-High (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range. For most operation at low power levels, the Average Power Range Monitor Neutron Flux-High (Setdown)

Function will provide a secondary scram to the Intermediate Range Monitor Neutron Flux-High Function because of the relative setpoints.

With the IRMs at Range 9 or 10, it is possible that the Average Power Range Monitor Neutron Flux-High (Setdown) Function will provide the primary trip signal for a core-wide increase in power.

No specific safety analyses take direct credit for the Average Power Range. Monitor Neutron Flux-High (Setdown) Function. However, this Function is credited in calculations used to eliminate the need to perform the spatial analysis required for the Intermediate Range Monitor Neutron Flux-High Function (Ref. 6). In addition, the Average Power Range Monitor Neutron Flux-High (Setdown) Function indirectly ensures that before the reactor mode switch is placed in the run position, reactor power does not exceed 23% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Therefore, it indirectly prevents fuel damage during significant reactivity increases with THERMAL POWER

< 23% RTP.

The Allowable Value is based on preventing significant increases in power when THERMAL POWER is< 23% RTP.

The Average Power Range Monitor Neutron Flux-High (Setdown)

Function must be OPERABLE during MODE 2 when control rods may be withdrawn since the potential for criticality exists.

continued

~---< A minimum of two OPERABLE LPRMs is required for an OPRM cell to be considered responsive.

Brunswick Unit 1 B 3.3.1.1-8 Revision No. 31 I

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE 2.e. 2-0ut-Of-4 Voter (continued)

SAFETY ANALYSES, LCO, and voted sets of Functions, each of which is redundant (four total outputs).

APPLICABILITY The analysis in Reference 15 took credit for this redundancy in the justification of the 12-hour Completion Time for Condition A, so the voter Function 2.e must be declared inoperable if any of its functionality is inoperable. The voter Function 2.e does not need to be declared inoperable due to any failure affecting only the APRM Interface hardware portion of the Two-Out-Of-Four Logic Module.

-~~~~~~~

There is no Allowable Value for this Function.

See Insert G for replacement of 2.f 2.f. Oscillation Power Range Monitor (OPRM) Upscale

~-----..............--.-.-..-..___,, The OPRM Upscale Function provides compliance with GOG 10 and GOG 12, thereby providing protection from exceeding the fuel MGPR safety limit (SL) due to anticipated thermal hydraulic power oscillations.

Brunswick Unit 1 References 17, 18 and 19 describe three algorithms for detecting thermal hydraulic instability related neutron flux oscillations: the period based detection algorithm, the amplitude based algorithm, and the growth rate algorithm. All three arc implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations. OPRM Upscale Function OPE:RABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Upscale Function receives input signals from the po*.ver range monitors (LPRMs) within the reactor core, which are combined into "cells" for evaluation by the OPRM algorithms. E:ach channel is capable of detecting thermal hydraulic instabilities, by detecting the related neutron flux oscillations, and issuing a trip signal before the MGPR SL is exceeded. Three of the four channels are required to be OPE: RAB LE:.

The OPRM Upscale trip is automatically enabled (bypass removed) when Tl=IE:RM/\\L POWE:R is ~ 26% RTP, as indicated by the APRM Simulated Thermal Power, and reactor core flow is ~ 60% of rated flow, as indicated by APRM measured recirculation drive flow. This is the operating region (continued)

B 3.3.1.1-13 Revision No. 31 I

~

2.f. Oscillation Power Range Monitor (OPRM) Upscale The OPRM Upscale Function provides compliance with 10 CFR 50, Appendix A, General Design Criteria (GDC) 1 O and 12, thereby providing protection from exceeding the fuel MCPR safety limit (SL) due to anticipated thermal-hydraulic power oscillations.

Reference 24 describes the Detect and Suppress Solution -Confirmation Density (DSS-CD) long-term stability solution and the licensing basis Confirmation Density Algorithm (CDA).

Reference 24 also describes the DSS-CD Armed Region and the three additional algorithms for detecting thermal-hydraulic instability related neutron flux oscillations: the period based detection algorithm (PBDA), the amplitude based algorithm (ABA), and the growth rate algorithm (GRA). All four algorithms are implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the CDA. The remaining three algorithms provide defense in depth and additional protection against unanticipated oscillations. OPRM Upscale Function OPERABILITY is based only on the CDA.

The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into cells for evaluation by the OPRM algorithms.

DSS-CD operability requires at least 8 responsive OPRM cells per channel. The DSS-CD software includes a self-test for the responsive OPRM cells; therefore, no SR is necessary.

The OPRM Upscale Function is required to be OPERABLE when the plant is 18% RTP, which is established as a power level that is greater than or equal to 5% below the lower boundary of the Armed Region. This requirement is designed to encompass the region of power-flow operation where anticipated events could lead to thermal-hydraulic instability and related neutron flux oscillations. The OPRM Upscale Function is automatically trip-enabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 23% RTP corresponding to the MCPR monitoring threshold and reactor recirculation drive flow is less than or equal to 75% of rated flow. This region is the OPRM Armed Region. Note (e) allows for entry into the DSS-CD Armed Region without automatic arming of DSS-CD prior to completely passing through the DSS-CD Armed Region during both the first startup and the first shutdown following DSS-CD implementation.

Note (f) reflects the need for plant data collection in order to test the DSS-CD equipment.

Testing the DSS-CD equipment ensures its proper operation and prevents spurious reactor trips. Entry into the DSS-CD Armed Region without automatic arming of DSS-CD during this initial testing phase also allows for changes in plant operations to address maintenance or other operational needs. However, during this initial testing period, the OPRM Upscale Function is OPERABLE and DSS-CD operability and capability to automatically arm shall be maintained at recirculation drive flow rates above the DSS-CD Armed Region flow boundary.

An OPRM Upscale trip is issued from an OPRM channel when the confirmation density algorithm in that channel detects oscillatory changes in the neutron flux, indicated by period confirmations and amplitude exceeding specified setpoints for a specified number of OPRM cells in the channel. An OPRM Upscale trip is also issued from the channel if any of the defense-in-depth algorithms (PBDA, ABA, GRA) exceeds its trip condition for one or more cells in that channel.

Three of the four channels are required to be operable. Each channel is capable of detecting thermal-hydraulic instabilities, by detecting the related neutron flux oscillations, and issuing a trip signal before the MCPR SL is exceeded. There is no Allowable Value for this function.

Insert G (continued)

The OPRM Upscale Function is not LSSS SL-related (Ref. 24) and Reference 25 confirms that the OPRM Upscale Function settings based on DSS-CD also do not have traditional instrumentation setpoints determined under an instrument setpoint methodology

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE 2.f. Oscillation Power Range Monitor (OPRM) Upscale SAFETY ANALYSES, (continued)

LCO, and APPLICABILITY where actual therR'lal hydraulic instability and related neutron flux oscillations R'lay occur. See Reference 21 for additional discussion of OPRM Upscale trip enable region liR'lits. The 26% RTP lower boundary of the enabled region was established by sealing the 30% value in Brunswick Unit 1 Reference 21 for uprated power to correspond to 30% of original plant RTP. This sealing is not required by Reference 21, but has been done for conservatism.

These setpoints, which are sometimes referred to as the "auto bypass" setpoints, establish the boundaries of the OPRM Upscale trip enabled region. The /\\PRM Simulated Thermal Power auto enable setpoint has 1 % deadband while the drive flow setpoint has a 2% dead band. The deadband f.or these setpoints is established so that it increased the enabled region.

The OPRM Upscale Function is required to be OPERABLE! when the plant is at ~ 20% RPT. The 20% RTP level is selected to provide margin in the unlikely event that a reactor power increase transient occurring

while the plant is operating below 25% RTP causes a power increase to or beyond the 26% /\\PRM Simulated Thermal Power OPRM Upscale trip auto enable setpoint without operator action. This OPER/\\BILITY requirement assures that the OPRM Upscale trip auto enable function will be OPERABLE *.vhen required.

/\\n OPRM Upscale trip is issued from an /\\PRM channel when the period based detection algorithm in that channel detects oscillatory changes in the neutron flux, indicated by the combined signals of the LPRM detectors in a cell, with period confirmations and relative cell amplitude exceeding specified setpoints. One or more cells in a channel exceeding the trip conditions will result in a channel trip. /\\n OPRM Upscale trip is also issued from the channel if either the grovlth rate or amplitude based algorithms detect gro*.ving oscillatory changes in the neutron flux for one or more cells in that channel. (Note: To facilitate placing the OPRM Upscale Function 2.f in one /\\PRM channel in a "tripped" state, if (continued)

B 3.3.1.1-14 Revision No. 31 I

BASES RPS Instrumentation B 3.3.1.1 APPLICABLE 2.f. Osoillation Power Range Monitor (OPRM) Upsoale (oontinued)

SAFETY ANALYSES, LCO, and neoessary to satisfy a Required /\\otion, the /\\PRM equipment is APPLICABILITY oonservatively designed to foroe an OPRM Upsoale trip output from the APRM ohannel if an /\\PRM lnop oondition ooours, suoh as when the APRM ohassis keylook switoh is plaoed in the lnop position.)

Brunswick Unit 1 There are four "sets" of OPRM related setpoints or adjustment parameters: (a) OPRM trip auto enable setpoints for Simulated Thermal Power (STP) (25%) and drive flow (00%); (b) period based deteotion algorithm (PBD/\\) oonfirmation oount and amplitude setpoints; (o) period based deteotion algorithm tuning parameters; and (d) growth rate algorithm (GRA) and amplitude based algorithm (ABA) setpoints.

The first set, the OPRM auto enable region setpoints, as disoussed in the SR d.d.1.1.1 Q Bases, are treated as nominal setpoints with no additional margins added. The settings, 25% APRM Simulated Thermal Power and 00% drive f.low, are defined (limit values) in and oonfirmed by SR d.d.1.1.19. The seoond set, the OPRM PBDAtrip setpoints, are established in aooordanoe i.vith methodologies defined in Referenoe 1 Q, and are dooumented in the COLR There are no allowable values for these setpoints. The third set, the OPRM PBDA "tuning" parameters, are established, adjusted, and oontrolled by plant prooedures. The fourth set, the GRA and ABA setpoints, in aooordanoe with Referenoes 15 and 10, are established as nominal values only, and oontrolled by plant prooedures.

3. Reactor Vessel Steam Dome Pressure-High An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This causes the neutron flux and THERMAL POWER transferred to the reactor coolant to increase, which could challenge the integrity of the fuel cladding and the RCPB. The Reactor Vessel Steam Dome Pressure-High Function initiates a scram for transients that results in a pressure increase, counteracting the pressure increase by rapidly reducing core power. For the overpressurization protection analyses of References 4, (continued)

B 3.3.1.1-15 Revision No. 58

BASES ACTIONS D.1 (continued)

RPS Instrumentation B 3.3.1.1 Condition D will be entered for that channel and provides for transfer to the appropriate subsequen~tion.

E.1, F.1, G.1, and J.4 ~

If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. The allowed Completion Times are easonable, based on operating experience, to reach the specified con *

n from full power conditions in an orderly manner and without challengin t systems. In addition, the Completion Time of Required Actions E.1 an J4 are consistent with the Completion Time provided in LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)."

H.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully

"""s---ee-1 n

...... s

...... e"'"rt"'""'"H"f"o"r "1. "1....... 1

....... 2............ inserted*

and 1.3, as well as J.1,

-14 J.2, J.3, and K.1 Condition I exists when the OPRM Upscale Trip capability has been

---.-...-.~~.._,__..._,._...._,.._,,.._.,._,.._,.._, lost for all APRM channels due to unantieipated equipFFlent design Brunswick Unit 1 or instability detection algorithFFl probleFFls, or when testing to confirFFl plant response/perforFFlanee following algorithFFl FFlodifieations.

References 16 and 16 justified use of alternate FFlethods to detect and suppress oscillations under liFFlited conditions. The alternate methods are procedurally established consistent with the guidelines identified in Reference 20. The alternate (continued)

B 3.3.1.1-28 Revision No. 34

1.1 If OPRM Upscale trip capability is not maintained, Condition I exists and Backup Stability Protection (BSP) is required. The Manual BSP Regions are described in Reference 24. The Manual BSP Regions are procedurally established consistent with the guidelines identified in Reference 24 and require specified manual operator actions if certain predefined operational conditions occur.

The Completion Time of immediate is based on the importance of limiting the period of time during which no automatic or manual BSP trip capability is in place.

1.2 and 1.3 Actions 1.2 and 1.3 are both required to be taken in conjunction with Action 1.1 if OPRM Upscale trip capability is not maintained. As described in Section 7.4 of Reference 24, the Automated BSP Scram Region is designed to avoid reactor instability by automatically preventing entry into the region of the power and flow-operating map that is susceptible to reactor instability. The reactor trip would be initiated by the modified APRM Simulated Thermal Power High scram setpoints for flow reduction events that would have terminated in the Manual BSP Region I. The Automated BSP Scram Region ensures an early scram and SLMCPR protection.

The Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to complete Action 1.2 is reasonable, based on operational experience, and based on the importance of restoring an automatic reactor trip for thermal-hydraulic instability events.

BSP is intended as a temporary means to protect against thermal-hydraulic instability events.

Action 1.3 should be initiated immediately to document the situation and prepare the report.

The reporting requirements of Specification 5.6. 7 document the corrective actions and schedule to restore the required channels to an OPERABLE status. The 90 day Completion Time shown in Specification 5.6.7 is adequate to allow time to evaluate the cause of the inoperability and to determine the appropriate corrective actions and schedule to restore the required channels to OPERABLE status.

J.1 If the Required Actions I are not completed within the associated Completion Times, then Action J is required. The Bases for the Manual BSP Regions and associated Completion Time is addressed in the Bases for 1.1. The Manual BSP Regions are required in conjunction with the BSP Boundary.

J.2 The BSP Boundary, as described in Section 7.3 of Reference 24, defines an operating domain where potential instability events can be effectively addressed by the specified BSP manual operator actions. The BSP Boundary is constructed such that a flow reduction event initiated from this boundary and terminated at the core natural circulation line (NCL) would not exceed the Manual BSP Region I stability criterion. Potential instabilities would develop slowly as a result of the feedwater temperature transient (Ref. 24).

The Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to complete the specified action is reasonable, based on operational experience, to reach the specific condition from full power conditions in an orderly manner and without challenging plant systems.

J.3 BSP is a temporary means for protection against thermal-hydraulic instability events. An extended period of inoperability without automatic trip capability is not justified. Consequently, the required channels are required to be restored to OPERABLE status within 120 days.

Based on engineering judgment, the likelihood of an instability event that could not be adequately handled by the use of the BSP Regions (See Action J.1) and the BSP Boundary (See J.2) during a 120-day period is negligibly small. The 120-day period is intended to allow for the case where limited design changes or extensive analysis might be required to understand or correct some unanticipated characteristic of the instability detection algorithms or equipment. This action is not intended and was not evaluated as a routine alternative to returning failed or inoperable equipment to OPERABLE status. Correction of routine equipment failure or inoperability is expected to normally be accomplished within the completion times allowed for Actions for Conditions A and B.

A Note is provided to indicate that LCO 3.0.4 is not applicable. The intent of that Note is to allow plant startup while operating within the 120-day Completion Time for Required Action J.3. The primary purpose of this exclusion is to allow an orderly completion of design and verification activities, in the event of a required design change, without undue impact on plant operation.

K.1 If the required channels are not restored to OPERABLE status and the Required Actions of J are not met within the associated Completion Times, then the plant must be placed in an operating condition in which the LCO does not apply. To achieve this status, the plant must be brought to less than 18% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reach the specified operating power level from full power conditions in an orderly manner and without challenging plant systems.

BASES ACTIONS SURVEILLANCE REQUIREMENTS Brunswick Unit 1 RPS Instrumentation B 3.3.1.1 L.1 (continued) methods procedures require operating outside a "restricted zone" in the power flow map and manual operator action to scram the plant if certain predefined events occur. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed Completion Time for Required /\\ction 1.1 is based on engineering judgment to allow orderly transition to the alternate methods while limiting the period of time during which no automatic or alternate detect and suppress trip capability is formally in place. Based on the small probability of an instability event occurring at all, the 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is judged to be reasonable.

This Required Action is intended to allo*w continued plant operation under limited conditions when an unanticipated equipment design or instability detection algorithm problem causes OPRM Upscale Function inoperability in all /\\PRM channels. This Required /\\ction is not intended and was not evaluated as a routine alternative to return failed or inoperable equipment to OPE:R/\\BU! status. Correction of routine equipment failure or inoperability is expected to be accomplished within the completion times allowed f.or Required /\\ctions for Condition A The alternate method to detect and suppress oscillations implemented in accordance with 1.1 is intended to be applied only as long as is necessary to implement and test corrective action to resolve the unanticipated equipment design or instability detection algorithm problem.

As noted at the beginning of the SRs, the SRs for each RPS instrumentation Function are located in the SRs column of Table 3.3.1.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 11, 15, and 16) assumption of the average time required to perform channel Surveillance.

(continued)

B 3.3.1.1-29 Revision No. 34

BASES SURVEILLANCE REQUIREMENTS Brunswick Unit 1 SR 3.3.1.1.11 (continued)

RPS Instrumentation B 3.3.1.1 The APRM CHANNEL FUNCTIONAL TEST covers the APRM channels (including recirculation flow processing - applicable to Function 2.b and the auto-enable portion of Function 2.f only), the 2-0ut-Of-4 Voter channels, and the interface connections into the RPS trip systems from the voter channels.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. The 184-day Frequency of SR 3.3.1.1.11 is based on the reliability analyses of References 15 and 16.

(NOTE: The actual voting logic of the 2-0ut-Of-4 Voter Function is tested as part of SR 3.3.1.1.15. The auto enable setpoints for the OPRM Upscale trip are confirmed by SR 3.3.1.1.19.)

A Note is provided for Function 2.a that requires this SR to be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM Function cannot be performed in MODE 1 without utilizing jumpers or lifted leads. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2.

A second Note is provided for Functions 2.b and 2.f that clarifies that the CHANNEL FUNCTIONAL TEST for Functions 2.b and 2.f includes testing of the recirculation flow processing electronics, excluding the flow transmitters.

SR 3.3.1.1.13 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. The CHANNEL CALIBRATION for Functions 5 and 8 should consist of a physical inspection and actuation of the associated position switches.

Note 1 states that neutron detectors are excluded from CHANNEL CALIBRATION because they are passive devices, with minimal drift, and because of the difficulty of simulating a meaningful signal. Changes in neutron detector sensitivity are compensated for by performing the 7 day (continued)

B 3.3.1.1-35 Revision No. 31 I

BASES SURVEILLANCE REQUIREMENTS Brunswick Unit 1 SR 3.3.1.1.13 (continued)

RPS Instrumentation B 3.3.1.1 calorimetric calibration (SR 3.3.1.1.3) and the 2000 EFPH LPRM calibration against the TIPs (SR 3.3.1.1.8).

A second Note is provided that requires the IRM SRs to be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of entering MODE 2 from MODE 1. Testing of the MODE 2 IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.

A third note is provided that requires that the recirculation flow (drive flow) transmitters, which supply the flow signal to the APRMs, be included in the SR for Functions 2.b and 2.f. The APRM Simulated Thermal Power-High Function (Function 2.b) and the OPRM Upscale Function (Function 2.f) both require a valid drive flow signal. The APRM Simulated Thermal Power-High Function uses drive flow to automatically enable or bypass the OPRM Upscale trip output to RPS. A CHANNEL CALIBRATION of the APRM drive flow signal requires both calibrating the drive flow transmitters and the processing hardware in the APRM equipment. SR 3.3.1.1.18 establishes a valid drive flow/core flow relationship. Changes throughout the cycle in the drive flow/core flow relationship due to the changing thermal hydraulic operating conditions of the core are accounted for in the margins included in the bases or analyses used to establish the setpoints for the APRM Simulated Thermal Power-High Function and the OPRM Upscale Function.

The Frequency of SR 3.3.1.1.13 is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.1.1.14 (Not used.)

B 3.3.1.1-36 (continued)

Revision No. 71 I

BASES SURVEILLANCE REQUIREMENTS Brunswick Unit 1 SR 3.3.1.1.17 (continued)

RPS Instrumentation B 3.3.1.1 The 24 month Frequency is consistent with the BNP refueling cycle and is based upon plant operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.

SR 3.3.1.1.18 The APRM Simulated Thermal Power-High Function (Function 2.b) uses drive flow to vary the trip setpoint. The OPRM Upscale Function (Function 2.f) uses drive flow to automatically enable or bypass the OPRM Upscale trip output to RPS. Both of these Functions use drive flow as a representation of reactor core flow. SR 3.3.1.1.13 assures that the drive flow transmitters and processing electronics are calibrated. This SR adjusts the recirculation drive flow scaling factors in each APRM channel to provide the appropriate drive flow/core flow alignment.

The Frequency of once within 7 days after reaching equilibrium conditions following a refueling outage is based on the expectation that any change in the core flow to drive flow functional relationship during power operation would be gradual and the maintenance on the Recirculation System and core components which may impact the relationship is expected to be performed during refueling outages. The 7 day time period after reaching equilibrium conditions is based on plant conditions required to perform the test, engineering judgment of the time required to collect and analyze the necessary flow data, and engineering judgment of the time required to enter and check the applicable scaling factors in each of the APRM channels. The 7-day time period after reaching equilibrium conditions is acceptable based on the relatively small alignment errors expected, and the margins already included in the APRM Simulated Thermal Power-High and OPRM Upscale Function trip-enable setpoints.

SR 3.3.1.1.19 This surveillance involves confirR'ling the OPRM Upscale trip auto enable setpoints. The auto enable setpoint values are considered to be noR'linal values as discussed in Reference 21. This surveillance ensures that the OPRM Upscale trip is enabled (not bypassed) for the correct values of (continued)

B 3.3.1.1-40 Revision No. 31 I

BASES SURVEILLANCE REQUIREMENTS REFERENCES Brunswick Unit 1 SR 3.3.1.1.19 (sontinued)

RPS Instrumentation B 3.3.1.1 APRM Simulated Thermal Power and resiroulation drive flow. Other surveillanses ensure that the APRM Simulated Thermal Power and resiroulation drive flow properly sorrelate with Tl=ffJ~MAL POWER (SR 3.3.1.1.3) and sore flow (SR 3.3.1.1.18), respestively.

In any auto enable setpoint is nonsonservative (i.e, the OPRM Upssale trip is bypassed when APRM Simulated Thermal Power ~ 25% and resiroulation drive flow ~ 60%), then the attested shannel is sonsidered inoperable for the OPRM Upssale Funstion. Alternatively, the OPRM Upssale trip auto enable setpoint(s) may be adjusted to plase the shannel in a sonservative sondition (not bypassed). If the OPRM Upssale trip is plased in the not bypassed sondition, this SR is met and the shannel is sonsidered OPERABLE.

The Frequensy of 24 months is based on engineering judgment and reliability of the somponents.

1.

2.

UFSAR, Section 7.2.

UFSAR, Chapter 15.0.

3.

UFSAR, Section 7.2.2.

4.

NEDC-32466P, Power Uprate Safety Analysis Report for Brunswick Steam Electric Plant Units 1 and 2, September 1995.

5.

10 CFR 50.36(c)(2)(ii).

6.

NED0-23842, Continuous Control Rod Withdrawal in the Startup Range, April 18, 1978.

7.

UFSAR, Section 5.2.2.

8.

UFSAR, Appendix 5A.

9.

UFSAR, Section 6.3.1.

(continued)

B 3.3.1.1-41 Revision No. 36 I

BASES REFERENCES (continued)

Brunswick Unit 1

10.

RPS Instrumentation B 3.3.1.1 P. Check (NRC) letter to G. Lainas (NRC), BWR Scram Discharge System Safety Evaluation, December 1, 1980.

11.

NEDC-30851 -P-A, Technical Specification Improvement Analyses for BWR Reactor Protection System, March 1988.

12.

MDE-81-0485, Technical Specification Improvement Analysis for the Reactor Protection System for Brunswick Steam Electric Plant, Units 1 and 2, April 1985.

13.

UFSAR, Table 7-4.

14.

NED0-32291-A, System Analyses for the Elimination of Selected Response Time Testing Requirements, October 1995.

15.

NEDC-3241 OP-A, Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option Ill Stability Trip Function, October 1995.

16.

NEDC-3241 OP-A, Supplement 1, Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM)

Retrofit Plus Option Ill Stability Trip Function, November 1997.

17.

NEDO 31Q60 /\\, BWR Owners' Group Long TerRl Stability Solutions Licensing Methodology, t>loveRlber 1 QQ5. Not used.

18.

t>lEDO 31 Q60 A, SuppleRlent 1, BWR Owners' Group Long TerRl Stability Solutions Licensing Methodology, t>loveRlber 19Q5. Not used.

19.

t>lEDO 32465 /\\, BWR Owners' Group Long TerRl Stability Detest and Suppress Solutions Licensing Basis Methodology and Reload Applications, August 1 QQ6. Not used.

20.

Letter, L. A. England (BWROG) to M. J. Virgilio, BWR Owners' Group Guidelines for Stability lnteriRl Corrective Action, June 6,

+gQ4.. Not used.

21.

BWROG Letter 96113, K. P. Donovan (BWROG) to L. E Phillips (t>lRC), Guidelines for Stability Option Ill "Enable Region" (T/\\G M92882), SepteRlber 17, 19Q6. Not used.

(continued)

B 3.3.1.1-42 Revision No. 36 I

BASES REFERENCES (continued)

22.

RPS Instrumentation B 3.3.1.1 General E:leotrio fl>Juolear energy Letter fl>JSA 01 212, DRi; C51 00251 00, A. Chung (GE:) to S. Chakraborty (GE:),

"Minimum fl>Jumber of Operable OPRM Cells for Option Ill Stability at Brunswiok 1 and 2," dune 8, 2001. Not used.

23.

Calculation 0821-1305, Core Monitoring LPRM Uncertainty and Sensitivity Decay.

24.

NEDC-33075P-A, Revision 8, "GE Hitachi Boiling Water Reactor Detect and Suppress Solution - Confirmation Density," November 2013.

25.

J. Harrison (GEH) letter to NRC, "NEDC-33075P-A, Detect and Suppress Solution -

Confirmation Density (DSS-CD) Analytical Limit (TAC No.

MD0277)," October 29, 2008 (ADAMS Accession No. ML083040052).

Brunswick Unit 1 B 3.3.1.1-43 Revision No. 71

BASES Recirculation Loops Operating B 3.

4.1 BACKGROUND

(continued) coolant begins to boil, creating steam voids within the fuel channel that continue until the coolant exits the core. Because of reduced moderation, the steam voiding introduces negative reactivity that must be compensated for to maintain or to increase reactor power. The recirculation flow control allows operators to increase recirculation flow which increases the overall core heat transfer. As a result, core voiding is reduced thereby overcoming the negative reactivity void effect. Thus, the reason for having variable recirculation flow is to compensate for reactivity effects of boiling over a wide range of power generation (i.e.,

approximately 60 to 100% of RTP) without having to move control rods and disturb desirable flux patterns.

Each recirculation loop is manually started from the control room. The MG set provides regulation of individual recirculation loop drive flows.

The flow in each loop is manually controlled.

APPLICABLE The operation of the Reactor Recirculation System is an initial condition SAFETY ANALYSES assumed in the design basis loss of coolant accident (LOCA). During a LOCA caused by a recirculation loop pipe break, the intact loop is assumed to provide coolant flow during the first few seconds of the accident. The initial core flow decrease is rapid because the recirculation pump in the broken loop ceases to pump reactor coolant to the vessel almost immediately. The pump in the intact loop coasts down relatively slowly. This pump coastdown governs the core flow response for the next several seconds until the jet pump suction is uncovered. The AREVA LOCA analyses assume mismatched flow in the recirculation loops. Mismatched flow has an insignificant impact on the fuel thermal margin during abnormal operational transients which are analyzed in Chapter 15 of the UFSAR (Ref. 2).

Plant specific LOCA analyses have b n performed assuming only one operating recirculation loop.

The COLR presents single loop operation LHGR limits in the form of a multiplier that is applied to the two loop oper ion APLHGR limits. This multiplier restricts the peak clad temperature fo a LOCA with a single recirculation loop operating below the correspon

g temperature for both loops operating.

continued The Maximum Extended Load Line Limit Analysis Plus (MELLLA+) operating domain is not analyzed for reactor recirculation single loop operation (SLO). Therefore, SLO is prohibited in the MELLLA+ operating domain (Ref. 4).

Brunswick Unit 1 B 3.4.1-2 Revision No. 77 I

BASES Recirculation Loops Operating B 3.4.1 APPLICABLE The transient analyses of Chapter 15 of the UFSAR have also been SAFETY ANALYSES evaluated for single recirculation loop operation. The evaluation (continued) concludes that results of the transient analyses are not significantly affected by the single recirculation loop operation. There is, however, an impact on the fuel cladding integrity SL since some of the uncertainties for the parameters used in the critical power determination are higher in single loop operation. The net result is an increase in the MCPR operating limit.

LCO APPLICABILITY Brunswick Unit 1 During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor (APRM)

Simulated Thermal Power-High Allowable Value is required to account for the different analyzed limits between two-recirculation drive flow loop operation and operation with only one loop. The APRM channel subtracts the t::,,W value from the measured recirculation drive flow to effectively shift the limits and uses the adjusted recirculation drive flow value to determine the APRM Simulated Thermal Power-High Function trip setpoint.

Recirculation loops operating satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 3).

Two recirculation loops are normally required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied. Alternate!

with onl one recirculation loop in operation, modifications to the required APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), and APRM Simulated Thermal Power-High Allowable Value (LCO 3.3.1.1), as applicable, must be applied to allow continued operation. The COLR defines adjustments or modifications required for the APLHGR, MCPR, and LHGR limits for the current operating cycle.

In MODES 1 and 2, requirements for operation of the Reactor Coolant Recirculation System are necessary since there is considerable energy in the reactor core and the limiting design basis transients and accidents are assumed to occur.

In MODES 3, 4, and 5, the consequences of an accident are reduced and the coastdown characteristics of the recirculation loops are not important.

operation in the MELLLA+ operating domain is not permitted and B 3.4.1-3 (continued)

Revision No. 77

BASES (continued)

ACTIONS A.1 B.1 and C.1 Recirculation Loops Operating B 3.4.1 With the requirements of the LCO not met, the recirculation loops must be restored to operation with matched flows within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than the required limits. The loop with the lower flow must be considered not in operation. Should a LOCA occur with one recirculation loop not in operation, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed to restore the inoperable loop to operating status.

Alternatively, if the single loop requirements of the LCO are applied to operating limits and RPS setpoints, as applicable, operation with only one recirculation loop would satisfy the requirements of the LCO and the initial conditions of the accident sequence.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Completion Time is based on the low probability of an accident occurring during this time period, on a reasonable time to complete the Required Action (i.e., reset the applicable limits or setpoints for single recirculation loop operation), and on frequent core monitoring by operators allowing abrupt changes in core flow conditions to be quickly detected.

This Required Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between the total jet pump flows of the two loops is greater than the required limits. However, in cases where large flow mismatches occur, low flow or reverse flow can occur in the low flow loop jet pumps, causing vibration of the jet pumps. If zero or reverse flow is detected, the condition should be alleviated by changing pump speeds to re-establish forward flow.

g,.+

With no recirculation loops in operation or th associated Completion Time of Condition A t met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In this condition, the recirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

~--\\.Since single loop operation is not permitted in the MELLLA+

operating domain the plant must immediately initiate action to exit this region.

(continued)

Brunswick Unit 1 B 3.4.1-4 Revision No. 77

BASES (continued)

SURVEILLANCE REQUIREMENTS REFERENCES Brunswick Unit 1 Recirculation Loops Operating B 3.4.1 SR 3.4.1.1 This SR ensures the recirculation loops are within the allowable limits for mismatch. At low core flow (i.e., < 75% of rated core flow), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can, therefore, be allowed when core flow is < 75% of rated core flow. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop.

The mismatch is measured in terms of the percent of rated core flow. If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered not in operation. The SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is consistent with the Surveillance Frequency for jet pump OPERABILITY verification and has been shown by operating experience to be adequate to detect off normal jet pump loop flows in a timely manner.

1.

2.

3.

UFSAR, Section 5.4.1.3.

UFSAR, Chapter 15.

10 CFR 50.36( c)(2)(ii).

NEDC-33006P-A, "Maximum Extended Load Line Limit Analysis Plus," Revision 3 B 3.4.1-5 Revision No. 77

v t e Letter Sequence Request
CAC:MF8864, Revise Shutdown Margin Definition to Address Advanced Fuel Designs (Approved, Closed)
Initiation Request, Request, Request, Request Acceptance Administration Questions 9 March 2017 2 October 2017 5 January 2018 5 January 2018 8 March 2018 12 March 2018 Answers 6 April 2017 1 November 2017 5 February 2018 1 March 2018 Results Approval Other:
MONTHYEAR2017-04-06 [Table View]

ML16257A410

Text

Subject:

Enclosures:

Subject:

Background

4.1 BACKGROUND

Navigation menu

Search