Text

And Vogtle Electric Generating Plant, Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen/Oxygen Monitors
	ML041470172
Person / Time
Site:	Hatch, Vogtle, Farley
Issue date:	05/21/2004
From:	Stinson L; Southern Nuclear Operating Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NL-04-0564
	Download: ML041470172 (138)
	v • d • e

L. M. Stinson (Mike)

Southern Nuclear Vice President Operating Company, Inc.

40 Inverness Center Parkway Post Office Box 1295 Birmingham, Alabama 35201 Tel 205.992.5181 Fax 205.992.0341 i

S@UT1HERIN1Z May 21, 2004 COMPAMY Ener vto Serve Yotr World9 Docket Nos.:

50-321 50-348 50-424 NLT4-0564 50-366 50-364 50-425 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Edwin I. IHatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen/Oxygen Monitors Using the Consolidated Line Item Improvement Process Ladies and Gentlemen:

Pursuant to 10 CFR 50.90, Southern Nuclear Operating Company (SNC) hereby requests amendments to the Technical Specifications (TS) for Units I and 2 of the Edwin 1. Hatch Nuclear Plant (IJNP), the Joseph M. Farley Nuclear Plant (FNP), and the Vogtle Electric Generating Plant (VEGP).

The proposed amendment will delete the TS requirements related to hydrogen recombiners, hydrogen monitors, and oxygen monitors. The proposed TS changes support implementation of the revision to 10 CFR 50.44, "Standards for Combustible Gas Control System in Light-Water-Cooled Power Reactors," that became effective on October 16, 2003. The changes are consistent with Revision I of NRC-approved Industry/Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-447, "Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors." The availability of this TS improvement was announced in the Federal Register on September 25. 2003 as part of the consolidated line item improvement process (CLIIP).

Enclosure I provides the basis for the proposed changes for HNP Units I and 2, FNP Units I and 2, and VEGP Units I and 2. This includes a description of the proposed changes, the confirmation of applicability, plant-specific verifications, the no significant hazards determination, and the environmental evaluation. Enclosure 2 provides the existing TS and TS Bases pages marked-up to show the proposed changes and the clean typed copies of the affected pages for HNP Units I and 2. Enclosures 3 and 4 similarly provide the marked-up and clean typed TS and TS Bases pages for FNP Units I and 2 and VEGP Units I and 2, respectively.

40(X)

U.S. Nuclear Regulatory Commission NL-04-0564 Page 2 The NRC commitments contained in this letter are provided in section 6.1 of Enclosure I for HNP, FNP and VEGP.

SNC requests approval of the proposed License Amendment by March 1, 2005 for HNP in order to support the spring 2005 Unit 2 outage and June 1, 2005 for FNP and VEGP.

The proposed changes will be implemented within 60 days of issuance of the amendment.

Mr. L. M. Stinson states he is a Vice President of Southern Nuclear Operating Company, is authorized to execute this oath on behalf of Southern Nuclear Operating Company and to the best of his knowledge and belief, the facts set forth in this letter are true.

If you have any questions regarding this submittal, please advise.

Respectfully submitted, SOUTHERN NUCLEAR OPERATING COMPANY L. M. Stinson Swi0orn to and subscribed before ine this 21 dal of

. 2004.

ANotary Public MAfIcozinission expirs-(Q L

LMS/TDIH/daj : Basis for Proposed Change : HNP Marked-up and Clean-typed TS and TS Bases Pages : FNP Marked-up and Clean-typed TS and TS Bases Pages : VEGP Marked-up and Clean-typed TS and TS Bases Pages cc:

Southern Nuclear Operating Company Mr. J. B. Beasley, Jr., Executive Vice President Mr. L. M. Stinson, Vice President, Plant Farley Mr. H. L. Sumner, Jr., Vice President, Plant Hatch Mr. J. T. Gasser, Vice President, Plant Vogtle Mr. D. E. Grissette, General Manager - Plant Farley Mr. G. R. Frederick, General Manager - Plant Hatch Mr. W. F. Kitchens, General Manager - Plant Vogtle RType: CFA04.054; CHA02.004; CVC7000; LC# 14018

U.S. Nuclear Regulatory Commission NL-04-0564 Page 3 U. S. Nuclear Regulatory Commission Dr. WV. D. Travers, Regional Administrator Mr. S. E. Peters, NRR Project Manager-Farley Mr. C. Gratton, NRR Project Manager - Hatch Mr. C. Gratton, NRR Project Manager - Vogtle Mr. C. A. Patterson, Senior Resident Inspector - Farley Mr. D. S. Simpkins, Senior Resident Inspector - Hatch Mr. J. Zeiler, Senior Resident Inspector - Vogtle State of Alabama Dr. D. E. Williamson, State Health Officer - Department of Public Health State of Georgia Mr. L. C. Barrett, Commissioner - Department of Natural Resources

Enclosure I Edwin 1. Hatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen and Oxygen Monitors Using the Consolidated Line Item Improvement Process Basis for Proposed Change

Enclosure I Edwin 1. Hatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen and Oxygen Monitors Using the Consolidated Line Item Improvement Process

1.0 INTRODUCTION

The proposed License amendment deletes Technical Specification (TS) requirements for the "Hydrogen Recombiners," and deletes references to the hydrogen and oxygen monitors in "Post Accident Monitoring (PAM) Instrumentation" sections of the TS. The proposed TS changes support implementation of the revisions to 10 CFR 50.44, "Standards for Combustible Gas Control System in Light-Water-Cooled Power Reactors," that became effective on October 16, 2003. The deletion of the requirements for the hydrogen recombiner and references to hydrogen and oxygen monitors resulted in numbering and formatting changes to other TS, which were otherwise unaffected by this proposed amendment.

The changes are consistent with Revision I of NRC-approved Industry/Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-447, "Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors." The availability of this TS improvement was announced in the Federal Register on September 25, 2003 as part of the consolidated line item improvement process (CLIIP).

2.0 DESCRIPTION

OF PROPOSED AMENDMENT Consistent with the NRC-approved Revision I of TSTF-447, the proposed TS changes include:

Edwin 1. Hatch Nuclear Plant (HNP)

TS TOC, page iii (Unit 2 only)

TS Table 3.3.3.1-1 TS Table 3.3.3.1-1 TS 3.6.3.1 (Unit 2 only)

Item 3.6.3.1 Item 7, Drywell Hydrogen Concentration Item 8, Drywell Oxygen Concentration Primary Containment Hydrogen Recombiners Deleted Deleted Deleted Deleted Joseph M. Farley Nuclear Plant (FNP)

TS TOC, page ii TS 3.3.3 TS 3.3.3 TS Table 3.3.3-1 TS 3.6.7 Item 3.6.7 Condition C, Note Condition D Item 18, Hydrogen Monitors Hydrogen Recombiners Deleted Deleted Deleted Deleted Deleted Vogtle Electric Generating Plant (VEGP)

TS TOC, page iii TS 3.3.3 TS Table 3.3.3-1 TS 3.6.7 Item 3.6.7 Condition I Item 19, Containment Hydrogen Monitors Hydrogen Recombiners Deleted Deleted Deleted Deleted El-1

Enclosure I Edwin I. Hatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen and Oxygen Monitors Using the Consolidated Line Item Improvement Process HNP Unit I was originally licensed with a combustible gas strategy of purging and venting; therefore, it does not have Post-LOCA (Loss of Coolant Accident) recombiners.

Consequently, the elimination of HNP TS 3.6.3.1 only applies to HNP Unit 2. Other TS changes included in this application are limited to renumbering and formatting changes that resulted directly from the deletion of the above requirements related to hydrogen recombiners and hydrogen and oxygen monitors. As described in NRC-approved Revision I of TSTF-447, the changes to TS requirements and associated renumbering of other TS results in changes to various TS Bases sections.

3.0 BACKGROUND

The background for this application is adequately addressed by the NRC Notice of Availability published on September 25, 2003 (68 FR 55416), TSTF-447, the documentation associated with the 10 CFR 50.44 rulemaking, and other related documents.

4.0 REGULATORY REOUIREMENTS AND GUIDANCE The applicable regulatory requirements and guidance associated with this application are adequately addressed by the NRC Notice of Availability published on September 25, 2003 (68 FR 55416), TSTF447, the documentation associated with the 10 CFR 50.44 rulemaking, and other related documents.

5.0 TECHNICAL ANALYSIS

SNC has reviewed the safety evaluation (SE) published on September 25, 2003 (68 FR 55416) as part of the CLIIP Notice of Availability. The analysis included a review of the NRC staff's SE, as well as the supporting information provided to support TSTF-447. SNC has concluded that the justifications presented in the NRC approved TSTF and the SE prepared by the NRC staff are applicable to Units I and 2 of FNP, HNP, and VEGP and justify this amendment for the incorporation of the changes to the applicable TS.

6.0 REGULATORY ANALYSIS

A description of this proposed change and its relationship to applicable regulatory requirements and guidance was provided in the NRC Notice of Availability published on September 25, 2003 (68 FR 55416), TSTF-447, the documentation associated with the 10 CFR 50.44 rulemaking, and other related documents.

El-2

Enclosure I Edwin I. Hatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen and Oxygen Monitors Using the Consolidated Line Item Improvement Process 6.1 Verification and Commitments As discussed in the model SE published in the Federal Register on September 25, 2003 (68 FR 55416) for this TS improvement, SNC is making the following verification and regulatory commitments:

I. SNC has verified that a hydrogen monitoring system capable of diagnosing beyond design-basis accidents is installed at FNP, HNP, and VEGP and is making a regulatory commitment to maintain that capability at the appropriate Regulatory Guide 1.97 category. The hydrogen monitors will be included in the post accident monitoring instrument program described in the FNP FSAR section 6.2.5, HNP Unit 2 FSAR section 7.5.3, and VEGP FSAR section 7.5.2. The FSAR will be revised at the next scheduled update following implementation of the TS amendment.

2. SNC has verified that FNP and VEGP do not have inerted containments.

Therefore, an oxygen monitoring system is not applicable.

3. SNC has verified that an oxygen monitoring system capable of verifying the status of the inerted HNP Units I and 2 containments is installed at HNP and is making a regulatory commitment to maintain that capability. HNP uses two separate 02 analyzers for monitoring the primary containment environment. HNP uses a commercial grade analyzer for the purposes of monitoring the containment during normal operation, thus satisfying the requirements of TS Surveillance Requirement (SR) 3.6.3.2.1. HNP uses Regulatory Guide 1.97 category I instrumentation for post-accident monitoring purposes. SNC commits to maintaining a monitor for insuring the primary containment is inerted (<4% 02 by volume) during normal operation. SNC also commits to maintaining a post-accident 02 analyzer for the purpose of insuring that the post-LOCA containment environment remains inerted. The post-accident 02 monitor will be maintained at the appropriate Regulatory Guide 1.97 category.

The commitment to maintain the post-accident H2 and 02 monitors will be maintained for both HNP Units I and 2, in the Unit 2 FSAR, section 7.5.3. The FSAR will be revised at the next scheduled update following implementation of this TS amendment. The post accident 02 monitors will be added to the Technical Requirements Manual simultaneously with the implementation of this TS amendment.

7.0 NO SIGNIFICANT HAZARDS CONSIDERATION SNC has reviewed the proposed no significant hazards consideration determination published on September 25, 2003 (68 FR 55416) as part of the CLIIP. SNC has concluded that the proposed determination presented in the notice is applicable to Units I and 2 of FNP, HNP, and VEGP and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91(a).

E1-3

Enclosure I Edwin I. Hatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen and Oxygen Monitors Using the Consolidated Line Item Improvement Process 8.0 ENVIRONMENTAL EVALUATION SNC has reviewed the environmental evaluation included in the model SE published on September 25, 2003 (68 FR 55416) as part of the CLIIP. SNC has concluded that the staff's findings presented in that evaluation are applicable to Units I and 2 of FNP, HNP, and VEGP and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. SNC is not proposing variations or deviations from the TS changes described in TSTF-447 or the NRC staff's model SE published on September 25, 2003 (68 FR 55416).

10.0 REFERENCES

Federal Register Notice: Notice of Availability of Model Application Concerning Technical Specification Improvement To Eliminate Hydrogen Recombiner Requirement, and Relax the Hydrogen and Oxygen Monitor Requirements for Light Water Reactors Using the Consolidated Line Item Improvement Process, published September 25, 2003 (68 FR 55416).

E1-4 Edwin I. Hatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen and Oxygen Monitors Using the Consolidated Line Item Improvement Process HNP Marked-up and Clean Typed TS and Bases Pages

TABLE OF CONTENTS (continued) 3.6 CONTAINMENT SYSTEMS.............................................

3.6-1 3.6.1.1 Primary Containment.............................................

3.6-1 3.6.1.2 Primary Containment Air Lock.............................................

3.6-3 3.6.1.3 Primary Containment Isolation Valves (PCIVs)............................................

3.6-7 3.6.1.4 Drywell Pressure.............................................

3.6-13 3.6.1.5 Drywell Air Temperature............................................. 3.6-14 3.6.1.6 Low-Low Set (LLS) Valves............................................. 3.6-15 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers..................... 3.6-17 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers................................... 3.6-19 3.6.2.1 Suppression Pool Average Temperature.............................................

3.6-21 3.6.2.2 Suppression Pool Water Level.............

................................ 3.6-24 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling..............

............ 3.6-25 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray............................. 3.6-27 3.6.3.1.

7

.............................................. 3.6-29 3.6.3.2 Primary Containment Oxygen Concentration 3.6-31 3.6.3.3 Drywell Cooling System Fans............................................................... 3.6-32 3.6.4.1 Secondary Containment............................................

...................... 3.6-33 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)..........3.6-36 3.6.4.3 Standby Gas Treatment (SGT) System...........................

3.6-39 (oUsed) 3.7 PLANT SYSTEMS................................

3.7-1 3.7.1 Residual Heat Removal Service Water (RHRSW) System..............

............ 3.7-1 3.7.2 Plant Service Water (PSW) System and Ultimate Heat Sink (UHS)..

3.7-3 3.7.3 Diesel Generator (DG) 1 B Standby Service Water (SSW)

System.................................................................................................. 3.7-6 3.7.4 Main Control Room Environmental Control (MCREC) System..................... 3.7-8 3.7.5 Control Room Air Conditioning (AC) System............................................. 3.7-12 3.7.6 Main Condenser Offgas.............................................

3.7-16 3.7.7 Main Turbine Bypass System............................................. 3.7-18 3.7.8 Spent Fuel Storage Pool Water Level.............................................

3.7-19 3.8 ELECTRICAL POWER SYSTEMS...................

.......................... 3.8-1 3.8.1 AC Sources - Operating.............................................

3.8-1 3.8.2 AC Sources - Shutdown.............................................

3.8-20 3.8.3 Diesel Fuel Oil and Transfer, Lube Oil, and Starting Air................

3.8-23 3.8.4 DC Sources - Operating................

3.8-26 3.8.5 DC Sources - Shutdown................

3.8-31 (continued)

HATCH UNIT 2 iii Amendment No. 169

PAM Instrumentation 3.3.3.1 Table 3.3.3.1-1 (page 1 of 1)

Post Accident Monitoring Instrumentation CONDITIONS REFERENCED REQUIRED FROM REQUIRED FUNCTION CHANNELS ACTION D.1

1.

Reactor Steam Dome Pressure

2.

Reactor Vessel Water Level

a.

-317 inches to -17 inches

b.

-150 inches to +60 inches

c.

0 inches to +60 inches

d.

0 inches to +400 inches

3.

Suppression Pool Water Level

a.

0 inches to 300 inches

b.

133 inches to 163 inches

4.

Drywell Pressure

a.

-10 psig to +90 psig

b.

-5 psig to +5 psig

c.

0 psig to +250 psig

5.

Drywell Area Radiation (High Range)

6.

Primary Containment Isolation Valve Position 2

2 2

2 1

2 2

2 per penetration flow path (a)(b) 2(c) 6 1 per DG 1 per DG 1 per DG 1 per DG 2

E E

NA E

E E

F E

El E

7.

8.

PTywe44=4- -oncentFatwon

-q (Not Used)

I 02vwl C<(oncnrtol

9.

Suppression Pool Water Temperature

10.

Drywell Temperature in Vicinity of Reactor Level Instrument Reference Leg

11.

Diesel Generator (DG) Parameters

a.

Output Voltage

b.

Output Current

c.

Output Power

d.

Battery Voltage

12.

RHR Service Water Flow NA NA NA NA E

(a)

Not required for isolation valves whose associated penetration flow path is isolated by at least one closed and deactivated automatic valve, dosed manual valve, blind flange, or check valve with flow through the valve secured.

(b)

Only one position indication channel is required for penetration flow paths with only one installed control room indication channel.

(c)

Monitoring each of four quadrants.

HATCH UNIT 1 3.3-24 Amendment No. 195

PAM Instrumentation 3.3.3.1 Table 3.3.3.1-1 (page 1 of 1)

Post Accident Monitoring Instrumentation CONDITIONS REFERENCED REQUIRED FROM REQUIRED FUNCTION CHANNELS ACTION D.1

1.

Reactor Steam Dome Pressure

2.

Reactor Vessel Water Level

a. -317 inches to -17 inches

b. -150 inches to +60 inches

c. 0 inches to +60 inches

d. 0 inches to +400 inches

3.

Suppression Pool Water Level

a. 0 inches to 300 inches

b. 133 inches to 163 inches

4.

Drywell Pressure

a. -10 psig to +90 psig

b. -5 psig to +5 psig

c. 0 psig to +250 psig

5.

Drywell Area Radiation (High Range)

6.

Primary Containment Isolation Valve Position 2

2 2

2 1

2 2

2 per penetration flow path(a)(b) 2(c) 6 1 per DG 1 per DG 1 per DG 1 per DG 2

E E

NA E

E E

F E

E E

7.

B.

IDr--well Cn Conc_ ntr ii l-Ma= Con (Not Used)

9.

Suppression Pool Water Temperature

10.

Drywell Temperature in Vicinity of Reactor Level Instrument Reference Leg

11.

Diesel Generator (DG) Parameters

a. Output Voltage

b. Output Current

c. Output Power

d. Battery Voltage

12.

RHR Service Water Flow NA NA NA NA E

(a)

Not required for isolation valves whose associated penetration flow path is isolated by at least one closed and deactivated automatic valve, dosed manual valve, blind flange, or check valve with flow through the valve secured.

(b)

Only one position indication channel is required for penetration flow paths with only one installed control room indication channel.

(c)

Monitoring each of four quadrants.

HATCH UNIT 2 3.3-24 Amendment No. 135

I~rimnrv Cn tainment Hvd rqen -ReGombinreF l

(Not Used) 3.6.3.1 3.6 CONTAINMENT SYSTEMS

/s

/k

^

A en_:

a__-_:_

__A 3.6.3.1 PgnjmarN GontaRinment Hvd~roqeR Kecmne HATCH UNIT 2 3.6-29 Amendment No. 135

Ir-:__

n:

,,,,IKFIF~~~~~a~y L]EHE1HH H

1V F

e1 LEUfEH-F l

(Not Used) 1-3.6.3.1 EQUIVEMENTS SURVEILLANCE FREQUE Y

Perform a sy em functional t/at for each primpf 24 mont h

l I

HATCH UNIT 2 3.6-30 Amendment No. 174

TABLE OF CONTENTS (continued) 3.6 CONTAINMENT SYSTEMS.............................................

3.6-1 3.6.1.1 Primary Containment.............................................

3.6-1 3.6.1.2 Primary Containment Air Lock............................................. 3.6-3 3.6.1.3 Primary Containment Isolation Valves (PCIVs)...........................................

3.6-7 3.6.1.4 Drywell Pressure.............................................

3.6-13 3.6.1.5 Drywell Air Temperature............................................. 3.6-14 3.6.1.6 Low-Low Set (LLS) Valves.............................................

3.6-15 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers............

........ 3.6-17 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers.........................

......... 3.6-19 3.6.2.1 Suppression Pool Average Temperature.............................................

3.6-21 3.6.2.2 Suppression Pool Water Level.............................................

3.6-24 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling.......................... 3.6-25 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray.................

........... 3.6-27 3.6.3.1 (Not used).............................................

3.6-29....

l 3.6.3.2 Primary Containment Oxygen Concentration............................................. 3.6-31 3.6.3.3 Drywell Cooling System Fans.............................................

3.6-32 3.6.4.1 Secondary Containment.............................................

3.6-33 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)......................................

3.6-36 3.6.4.3 Standby Gas Treatment (SGT) System.............................................

3.6-39 3.7 PLANT SYSTEMS.............................................

3.7-1 3.7.1 Residual Heat Removal Service Water (RHRSW) System.......................... 3.7-1 3.7.2 Plant Service Water (PSW) System and Ultimate Heat Sink (UHS)..

3.7-3 3.7.3 Diesel Generator (DG) 1 B Standby Service Water (SSW)

System.................................................................................................. 3.7-6 3.7.4 Main Control Room Environmental Control (MCREC) System.................... 3.7-8 3.7.5 Control Room Air Conditioning (AC) System.............................................

3.7-12 3.7.6 Main Condenser Offgas.............................................

3.7-16 3.7.7 Main Turbine Bypass System............................................. 3.7-18 3.7.8 Spent Fuel Storage Pool Water Level..........................

................... 3.7-19 3.8 ELECTRICAL POWER SYSTEMS....................

......................... 3.8-1 3.8.1 AC Sources - Operating.............................................

3.8-1 3.8.2 AC Sources - Shutdown.............................................

3.8-20 3.8.3 Diesel Fuel Oil and Transfer, Lube Oil, and Starting Air................

3.8-23 3.8.4 DC Sources - Operating................

3.8-26 3.8.5 DC Sources - Shutdown................

3.8-31 (continued)

HATCH UNIT 2 iii Amendment No.

PAM Instrumentation 3.3.3.1 Table 3.3.3.1-1 (page 1 of 1)

Post Accident Monitoring Instrumentation CONDITIONS REFERENCED REQUIRED FROM REQUIRED FUNCTION CHANNELS ACTION D.1

1.

Reactor Steam Dome Pressure

2.

Reactor Vessel Water Level

a.

-317 inches to -17 inches

b. -150 inches to +60 inches

c.

0 inches to +60 Inches

d.

0 inches to +400 Inches

3.

Suppression Pool Water Level

a. 0 inches to 300 inches

b.

133 inches to 163 inches

4.

Drywell Pressure

a. -lopsigto+90psig

b.

-5 psig to +5 psig

c.

0 psig to +250 psig

5.

Drywell Area Radiation (High Range)

6.

Primary Containment Isolation Valve Position

7.

(Not used)

8.

(Not used)

9.

Suppression Pool Water Temperature

10.

Drywell Temperature in Vicinity of Reactor Level Instrument Reference Leg

11.

Diesel Generator (DG) Parameters

a. Output Voltage

b.

Output Current

c.

Output Power

d.

Battery Voltage

12.

RHR Service Water Flow 2

2 2

2, 1

2 2

2 per penetration flow path (IXb) 2(c) 6 1 per DG 1 per DG 1 per DG 1 per DG 2

E E

NA E

E E

F E

I E

E NA NA NA NA E

(a)

Not required for isolation valves whose associated penetration flow path is isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.

(b)

Only one position indication channel is required for penetration flow paths with only one installed control room indication channel.

(c)

Monitoring each of four quadrants.

HATCH UNIT 1 3.3-24 Amendment No.

PAM Instrumentation 3.3.3.1 Table 3.3.3.1-1 (page 1 of 1)

Post Accident Monitoring Instrumentation CONDITIONS REFERENCED REQUIRED FROM REQUIRED FUNCTION CHANNELS ACTION D.1

1.

Reactor Steam Dome Pressure

2.

Reactor Vessel Water Level

a. -317 inches to -17 inches

b. -150 Inches to +60 inches

c. 0 Inches to +60 Inches

d. 0 inches to +400 inches

3.

Suppression Pool Water Level

a. 0 inches to 300 inches

b. 133 inches to 163 inches

4.

Drywell Pressure

a. -10 psig to +90 psig

b. -5 psig to +5 psig

c. 0 psig to +250 psig

5.

Drywell Area Radiation (High Range)

6.

Primary Containment Isolation Valve Position

7.

(Not used)

8.

(Not used)

9.

Suppression Pool Water Temperature

10.

Drywell Temperature in Vicinity of Reactor Level Instrument Reference Leg

11.

Diesel Generator (DG) Parameters

a. Output Voltage

b. Output Current

c. Output Power

d. Battery Voltage

12.

RHR Service Water Flow 2

2 2

2 1

2 2

2 per penetration flow path(a)(b) 2(c) 6 1 per DG 1 per DG 1 per DG 1 per DG 2

E E

NA E

E E

F E

I I

E E

NA NA NA NA E

(a)

Not required for isolation valves whose associated penetration flow path is isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.

(b)

Only one position indication channel is required for penetration flow paths with only one installed control room indication channel.

(c)

Monitoring each of four quadrants.

HATCH UNIT 2 3.3-24 Amendment No.

(Not used) 3.6.3.1 3.6 CONTAINMENT SYSTEMS 3.6.3.1 (Not used)

HATCH UNIT 2 3.6-29 Amendment No.

(Not used) 3.6.3.1 (This page intentionally left blank.)

HATCH UNIT 2 3.6-30 Amendment No.

TABLE OF CONTENTS (continued)

B 3.6 CONTAINMENT SYSTEMS.................

............................. B 3.6-1 B 3.6.1.1 Primary Containment..............................................

B 3.6-1 B 3.6.1.2 Primary Containment Air Lock....................

.......................... B 3.6-6 B 3.6.1.3 Primary Containment Isolation Valves (PCIVs).................................... B 3.6-13 B 3.6.1.4 Drywell Pressure.............................................. B 3.6-28 B 3.6.1.5 Drywell Air Temperature.............................................. B 3.6-30 B 3.6.1.6 Low-Low Set (LLS) Valves..............................................

B 3.6-33 B 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers.............. B 3.6-36 B 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers................

............ B 3.6-41 B 3.6.2.1 Suppression Pool Average Temperature.............................................. B 3.6-47 B 3.6.2.2 Suppression Pool Water Level..............................................

B 3.6-52 B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling.................... B 3.6-55 B 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray...................... B 3.6-59 B 3.6.3.1 11F~a.FGnanetHd~e eob~F!B366 B 3.6.3. lPrimar Contaimcnt Hydogen Recmbincrs......................................... B363/

B 3.6.3.2 Primary Containment Oxygen Concentration.................................... B 3.6 B 3.6.3.3 Drywell Cooling System Fans.................................

B 3.6 B 3.6.4.1 Secondary Containment.................................

\\

B 3.6 B 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)............................ B 3.6 B 3.6.4.3 Standby Gas Treatment (SGT) System.................................. \\

B 3.6 (continued)

HATCH UNIT2 iv Revision 1

PAM Instrumentation B 3.3.3.1 BASES LCO

6. Primary Containment Isolation Valve (PCIV) Position (continued)

PCIV position is provided for verification of containment integrity. In the case of PCIV position, the important information is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each active PCIV in a containment penetration flow path, i.e., two total channels of PCIV position indication for a penetration flow path with two active valves. For containment penetrations with only one active PCIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient to redundantly verify the isolation status of each isolable penetration via indicated status of the active valve, as applicable, and prior knowledge of passive valve or system boundary status. If a penetration flow path is isolated, position indication for the PCIV(s) in the associated penetration flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flow path is not required to be OPERABLE. The indication for each PCIV consists of green and red indicator lights that illuminate to indicate whether the PCIV is fully open, fully closed, or in a mid-position. Therefore, the PAM specification deals specifically with this portion of the instrumentation channel.

,/l (Not Used)l Dr7.8well hydrogen and oxygen analyzerS are Type A instruments provided to detect high hydrogen or oxygen concentration conditions that represeRt a potential for cnntainment breach. This Yariable is also important in verifying the adequacy of mitigating actions. High hydrogen and oxygen concentration is measured by two independent analyzers and continuously recorded on two recorders in the control room. The analyzers have the capability for sampling both the drywell and the torus. The available 0 10% range of these analyzers satisfies the criteria of RG 1.97. These recorders are the primary indication used by the operator during an accident. Therefore, the PA*M specification deals specifically with this portion of the instrument Ghaennel

9. Suppression Pool Water Temperature Suppression pool water temperature is a Type A variable provided to detect a condition that could potentially lead to containment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression pool water temperature (continued)

HATCH UNIT 1 B 3.3-63 REVISION 1

PAM Instrumentation B 3.3.3.1 BASES LCO

6. Primary Containment Isolation Valve (PCIV) Position (continued)

PCIV position is provided for verification of containment integrity. In the case of PCIV position, the important information is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each active PCIV in a containment penetration flow path, i.e., two total channels of PCIV position indication for a penetration flow path with two active valves. For containment penetrations with only one active PCIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient to redundantly verify the isolation status of each isolable penetration via indicated status of the active valve, as applicable, and prior knowledge of passive valve or system boundary status. If a penetration flow path is isolated, position indication for the PCIV(s) in the associated penetration flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flow path is not required to be OPERABLE. The indication for each PCIV consists of green and red indicator lights that illuminate to indicate whether the PCIV is fully open, fully closed, or in a mid-position. Therefore, the PAM specification deals specifically with this portion of the instrumentation channel.

l (Not Used)

G 7., 8. [Drywell Hyl

rn and Oxgenl Ao e

Drywelt-hydrogen-and oxygert-analy-rs-are-Type-A instruments provided to deteGt high hydrogen or oxygen coRnGeatiOR GORditions that-repfesenapotential for Gontainment breach. This variable4s also importaRt~irverifyng the adequaGy of mitgatng-aGtiers-Hgh hydrogen and oxygen concentration is mcasured by two indepede.t aayzrs and GantinuouslyFeGFde--

wore~ersqn the-contrel room. T e aalyzer&-have the Gapabiliyfor sampfing-boththe-drywel-and the torus. The available 0 10% range of these analyzers satisfies6he-riteria of RG 1.97. These-eGorder are the pimary irdiGatien-usedbthe-operator-d g a cirTHherelfore, the PAM specification deals specifically with this portion of the instrumert

9. Suppression Pool Water Temperature Suppression pool water temperature is a Type A variable provided to detect a condition that could potentially lead to containment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression pool water temperature (continued)

HATCH UNIT 2 B 3.3-63 REVISION 1

Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.7 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers BASES BACKGROUND The function of the reactor building-to-suppression chamber vacuum breakers is to relieve vacuum when primary containment depressurizes below reactor building pressure. If the drywell depressurizes below reactor building pressure, the negative differential pressure is mitigated by flow through the reactor building-to-suppression chamber vacuum breakers and through the suppression-chamber-to-drywell vacuum breakers. The design of the external (reactor building-to-suppression chamber) vacuum relief provisions consists of two vacuum breakers (a mechanical vacuum breaker and an air operated butterfly valve), located in series in each of two lines from the reactor building to the suppression chamber airspace. The butterfly valve is actuated by differential pressure. The mechanical vacuum breaker is self actuating and can be remotely operated for testing purposes. The two vacuum breakers in series must be closed to maintain a leak tight primary containment boundary.

A negative differential pressure across the drywell wall is caused by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, inadvertent primary containment spray actuation, and steam condensation in the event of a primary system rupture. Reactor building-to-suppression chamber vacuum breakers prevent an excessive negative differential pressure across the primary containment boundary. Cooling cycles result in minor pressure transients in the drywell, which occur slowly and are normally controlled by heating and ventilation equipment. Inadvertent spray actuation results in a more significant pressure transient and becomes important in sizing the external (reactor building-to-suppression chamber) vacuum breakers.

inerting/de-inerting of the primary containment.

Increased differential pressure between the reactor building and the drywell can also be caused by operations which remove gas from the welf. Such operations inrli id,functional testing of the primary containment hydrogen recombinre.

The external vacuum breakers are sized on the basis of the air flow from the secondary containment that is required to mitigate the depressurization transient and limit the maximum negative containment (drywell and suppression chamber) pressure to within design limits. The maximum depressurization rate is a function of the primary containment spray flow rate and temperature and the (continued)

HATCH UNIT 2 B 3.6-36 REVISION 1 l

Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.8 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers BASES BACKGROUND The function of the suppression chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell. There are 12 internal vacuum breakers located on the vent header of the vent system between the drywell and the suppression chamber, which allow air and steam flow from the suppression chamber to the drywell when the drywell is at a negative pressure with respect to the suppression chamber.

Therefore, suppression chamber-to-drywell vacuum breakers prevent an excessive negative differential pressure across the wetwell drywell boundary. Each vacuum breaker is a self actuating valve, similar to a check valve, which can be remotely operated for testing purposes.

A negative differential pressure across the drywell wall is caused by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, inadvertent drywell spray actuation, and steam condensation from sprays or subcooled water reflood of a break in the event of a primary system rupture. Cooling cycles result in minor pressure transients in the drywell that occur slowly and are normally controlled by heating and ventilation equipment. Spray actuation or spill of subcooled water out of a break results in more significant pressure transients and becomes important in sizing the internal vacuum breakers.

Increased differential pressure between the suppression chamber and the drywell can also be caused by operations which add gas to the suppression chamber or remove gas from the drywell. Such conrtainent.eclude andinestingote pNe na Gt tae riar containment.

In the event of a primary system rupture, steam condensation within the drywell results in the most severe pressure transient. Following a primary system rupture, air in the drywell is purged into the suppression chamber free airspace, leaving the drywell full of steam.

Subsequent condensation of the steam can be caused in two possible ways, namely, Emergency Core Cooling Systems flow from a recirculation line break, or drywell spray actuation following a loss of coolant accident (LOCA). These two cases cases determine the maximum depressurization rate of the drywell.

In addition, the waterleg in the Mark I Vent System downcomer is controlled by the drywell-to-suppression chamber differential (continued)

HATCH UNIT 2 B 3.6-41 REVISION 1

-- -B 3.6.3.1-11Firlmar Csontainment AvaroqeR RecoDnr (Not Used)

B 3.6.3.1 B 3.6 RY-99 B 3.6.3.1 rimary Conta' ment Hydroge Recombiners BASE KGROUND The pri ry containme hydrogen reco iner eliminate the potent' breach of pri ary containmen ue to a hydroo n oxygen reac' n and is part qcombustible ga control require by 10 CFR r'50.$4, "Standards Xor Combustible Gs Control Syst ms in Light-W ter-Cooled Re ctors" (Ref. 1), a d GDC 41, "Citainment tmosphere Cle nup" (Ref. 2). T e primary cont inment hydrog n recombiner is quired to reduc the hydrogen ncentration in e

primary cont nment following loss of coola accident (LOC ). The primary coqinment hydrog recombiner a complishes thi by recombini ghydrogenand xygentoform eatervapor. T vapor remains f the primary co ainment, thus iminating any ischarge to the eny ronment. The p ary containm nt hydrogen re ombiner is man Ily initiated sinc flammability Ii ts would not b reached until sev ral days after a sign Basis Ac,dent (DBA).

e primary cont ament hydroge recombiner fu ctions to maint he hydrogen ga concentration ithin the conta' ment at or belo th flammability li of 4.0 volume ercent (v/o) fo owing a postula d LOCA. It is f y redundant a consists of o 100% capacity subsystems Each primary,!ntainment hy rogen recombin r consists o an enclosed blp er assembly, eater section, r action chambe direct contact rater spray gas ooler, water se rator, and associ ed piping, valv., and instrum ts. The prima containment hydro en recombiner ill be manuall initiated from th main control roo when the hydr gen gas concetration in the pr-ary co ainment reac s 3.3 v/o. Wh the primary cotain ment is irted (oxygen ncentration <.0 /o), the prim ry containment ydrogen reco iner will only f nction until the gen is used up (2.0 v/o hydro en combines ith 1.0 v/o oxyg

). Two recombi.drs are provide o meet the re irement for red dancy and independe ce. Each reco biner is powere from a separate Engineer d Safety Feat e bus and is pro ided with separa power panel aI dcontrol pane The rocess gas cir lating through t ge heater, the rea on chamber, an the cooler is a tomatically regu ted to 150 scfm the use of an o ice plate instaJIed in the cooler, he process gas 's heated to pproximately P000F. The hyd gen and oxygen ases are recombined it'o water vapor, yIich is then cond sed in the wate ontinued)

HATCH UNIT 2 B 3.6-63 REVISION I

BASES BACKS( OUND spray gas coler by the asso iated residual h t removal sub em 6ontinued) and discha ed with some f the effluent pro ess gas to the suppressi n chamber. T majority of the ooled, effluent rocess gas is ed with the in ming process g s to dilute the i coming gas prior tyhe mixture entring the heater,.ction.

N

%PPLICA LE yf(e primary con nment hydroge ecombiner pr vides the cap 4ty 3AFETY ANALYSES of controlling t bulk hydrogen oncentration in rimary contai ent to less than t lower flammab concentration f 4.0 v/o follong a DBA. This ntrol would preent a primary c tainment wid 1 hydrogen rn, thus ensuri that pressurer nd temperatur condition assumedinthe nalysis are noyexceeded. Th limiting DBA re tive to hydroge eneration is a OCA.

Hydr gen may accum late in primary ontainment fol wing a LOCA as result of:

A metal stam reaction b een the zirco um fuel rod cladding nd the reactor oolant; or

b.

Radio ic decomposi on of water i e Reactor Cool b.J Sys m.

in/e Col To evalu' te the potentia or hydrogen a 'cumulation in pr ary contai ent following LOCA, the hy ogen generatio is calculated as a f nction of time f Ilowing the init' tion of the acci9nt.

Ass ptions recoi ended by Ref ence 3 are use to maximize the a

unt of hydrog calculated.

he calculation onfirms that w en the mitigatin systems are actuated in ac ordance with e ergency proceg res, the peak hydrogen co centration in t primary contai ent is < 4.0 v/o (Ref. 4).

The pri ary containme hydrogen reco biners satisfy Cri non 3 of the N Policy State ent (Ref. 5).

7

//ontinued)

HATCH UNIT B a 6-64 REVISION 1

10,;-aw GentaiRmeRt HvdFc).qeR ReG BASES (cghtinued) 7 LCO Two primary c nainment hydrien recombiners 4ust be OPERABLE.

his ensures o ration of at least ne primary containme hydrogen reco biner subsystem n the event of orst case sing active failure.

Opera n with at least ne primary conta ment hydroge ecombiner subs etem ensures t t the post-LOCA ydrogen conce tration can be fevented from e ceeding the flam ability limit.

./

,//

Z 1

AP ABIL ITY In MODES 1 d 2, the two priry containmenyfydrogen recombiners are required to c96trol the hydrogpn concentratiorfwithin primary co ainment below it, flammability lirpft of 4.0 v/o folling a LOCA, a uming a worst c,- e single failure In MO E 3, both the hy§1 en productio rate and the tJtal hydrogen prod ced after a LO C Iwoud be less tan that calculatpd for the DB LOCA. Also, b cause of the lim'jed time in this ODE, the p bability of an ac dent requiring t e primary cont nment hydrogen combiner is lowTherefore, the rimary contain ent hydrogen recombiner is n required in MO E 3.

In MODES 4 nd 5, the proba ility and conse ences of a LOCA. are low due to t e pressure and,temperature limjtations in these lvJ)DES.

Therefore he primary con ainment hydrog, recombiner is (ot required these MODE Ie edo 1

NCTIONS A.

ith one prima containment h drogen recombi r inoperable, the inoperable reci mbiner must b restored to OPE BLE status with' 30 days. In is Condition, t remaining OPE BLE recombiner is adequate tp'perform the hyr rogen control fu tion. However, t overall re bility is reduc because a sing! failure in the OPERA LE recombiner ould result in re ced hydrogen coIrol capab ty. The 30 day ompletion Time s based on the lo prob ility of the occirrence of a LOCythat would gener e hyd,/ogen in amounjt capable of exc

~ding the flammab) ity limit, the arount of time available after the eyent for operator a ion to prevent Aceeding this Ii it, and the low p 6bability of failure g the OPERABLE prnary containme hydrogen recom6er.

(co nued)

HATCH UNIT//

B 3.,65 R; 4 ISION 1

!Prknap, Gen4nment HvdFoqei; ReGoFnbineF6 i

BASES ACTIO A1 (continue

/

Required tion A.1 has be n modified by a jote indicating t tthe provision of LCO 3.0.4 ar not applicable.

s a result, a M E

change allowed when ne recombiner is noperable. Thi

/

allowa ce is provided Iecause of the low robability of th occurrence of a OCA that would Aenerate hydrog in amounts ca able of exc eding the flam ability limit, the lo, probability of t e failure of the o ERABLE subs tem, and the am unt of time avai ble after a stulated LOC or operator actio to prevent exc eding the lammabilityIim.

B.1 and B.

With tw primary contain ent hydrogen r ombiners inop able, the i!

ability o perform the hy rogen control fu fction via altern e caps ilities must be v fied by administrative means w in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Th alternate hydrog n control capa ities are provid by the P frnary Containme t Purge Systemr the Nitrogen nerting System.

he 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Comp6tion Time allow a reasonable nrod of time to verify that a loss f hydrogen co (rol function do not exist. In addition, the al mrnate hydroge control system apability must b verified once er 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months th eafterto ensury its continued availability.

oth the initial v rification and subsequent yen cations may be p ormed as an a ministrative ch k by examiningJ gs or other inf rmation to deter ine the availa ity of the alterna)e hydrog n control systeV. It does not m n to perform th Sun, Klances needed o demonstrate PERABILITY ofte alternate c hyd gen control sy em. If the abili to perform the l$drogen co trol function is rintained, cont ued operation is/permitted with o hydrogen rec.mbiners inoper ble for up to 7 d 's. Seven days' reasonable ti e to allow two drogen recombirers to be

/

inoperable be ause the hydro n control functiqe is maintained an because of te low probabilit'of the occurren c of a LOCA that uld generate h rogen in amo ts capable of e feeding the flammnbility limit.

(coynitinued)

-HATCH UNIT/

/

B 3.6-66 7VISION 1

I

prmap'; Gentaonment HvdFoqeR ReGp.m.b;F;eF_6l BASES ACTIO

//

1//

CTntinued)

If any Req ed Action and sociated Compl$ion Time cann t be met, the p ant must be bro ght to a MODE irwhich the LCO oes not apply.

achieve this s tus, the plant mu t be brought to ;t least MODE within 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed C mpletion Time 1' 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is re onable, based n operating expe ence, to reach MODE 3 from fullower condition in an orderly ma er and without hallenging p/ htsystems.

II P

P SU F/EILLANCE SR 3.6.3.1.

UIREMENTS

/

Performa ce of a system fy ctional test for ach primary co tainment hydrogn recombiner en res that the rec mbiners are 0 RABLE and c attain and sustydn the temperaty/e necessary fo hydrogen reco bination. In paricular, this SR v#;ifies that the m imum heater sh ath temperature jcreases to 2 1 6oF in S 1.5 h rs and that it is aintained > 11505 and F

I or 2 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months th eafter to check e ability of the r combiner to fu tion properly d to make sure /

that significant ater elements pfe not burned ot). The 24 mont I Frequency is sed on a revie of the survei test history Reference 6 h

a

/

S R 3.6..1.2 This ensures ther are no physica problems that c Id affect Trec mbiner operatio. Since the re mbiners are me anically p

sive, except fo he blower assp 4blies, they are bject to only inimal mechan,£a failure. The'ly credible failu s involve loss of power or blowe function, blockge of the interna low path, missile impact, etc.

A visual in ection is suffi 4nt to determine normal conditio that could ca e such failures The 24 month F equency is based n a review the surveillan test history and eference 6.

(cotinuedl HATCH UNIT/

B 3.3667 R

1510N3'

Q-Rta;;meRt HVdFOqeF; Re ASES

/

URV1 -LANCE SR 3.6.3.1.3 REQlV REMENTS f

E continued)

This SR re uires performa e of a resistanc o ground test oeach heater p se to make sur, that there are n detectable gro 4ds in any he er phase. This* accomplished b verifying that t resista nce to ground f any heater ph5. is Ž 1,000,000) hms.

Th 24 month Freq ency is based on$ review of the rveillance tes

/ tory and Ref ce 6.

/

RE RENCES

1.

10 R50.44.

2.

CFR 50, Appen ix A, GDC 41.

3.

Regulatory Gui 1.7, Revision March 1971.

/4./

FSAR, Secti n 6.2.5.

NRC No. 3-102, "Final P cy Statement n Technical Specific tion Improvem ts," July 23, 193.

6.

NR ty Evaluati eport for dment 174.

ATCH UNIT B 3. -68 R 110N

Primary Containment Oxygen Concentration B 3.6.3.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.2 Primary Containment Oxygen Concentration BASES BACKGROUND Boiling water reactors must be designed to withstand events that generate hydrogen either due to the zirconium metal water reaction in the core or due to radiolysis. The primary method to control hydrogen is to inert the primary containment. With the primary containment inert, that is, oxygen concentration < 4.0 volume percent (v/o), a combustible mixture cannot be present in the primary containment for any hydrogen concentration.[ The capability to inert the rmr containment and maintain oxygen - 10 voworlstother with the Hydrogen Rccombiner System (LCO 3.6.3.1, "Primary Containment Hydrogen Recombiners") and the Drywell Cooling System fans (LCO 3.6.3.2, "Dns ywll Cooling System Fans") to provide redundant and diverse ethodn-to mitigate events that peoduse hydrogen. Ffi exapeAn event that rapidly generates hydrogen from zirconium imetal waOr reaction will result in excessive hydrogen in primary L

con ainment, but oxygen concentration will remain < 4.0 v/o and no combustion can occur Song term generation of both hydrogen and oxygen f.m vadiolduig deompeationi of water may eventually result in a combustible mixture in prmr coIntainment, except that the hydtrragR en ro

-li --

raye~ hydrlgen andt exgR gases fter than they ran be produced from Fadielysis an~d agan nc mbution Gan occurf T-his1?,O ens~ures thTat oxy~gen concentraition do5es not exceed 4.0 v/o during operation in the applicable conditions.

APPLICABLE SAFETY ANALYSES The Plant Hatch Individual Plant Examination (Ref. 1) assumes that the primary containment is inerted when a Design Basis Accident loss of coolant accident occurs. Thus, the hydrogen assumed to be released to the primary containment as a result of metal water reaction in the reactor core will not produce combustible gas mixtures in the primary containment. jOxygen, which is subsequently Ienerated hb radinvtiric r

d rncomRooition of iater. is recoarnhend.c hvb the hydrogen recombiners - - -- ---V - ---- -- - -.

it

t % --

AL I- -

u X AII I

RLLAJ 3..3 More Fpauivl !RaR it IS EpFEOUG60.

II The primary containment oxygen concentration satisfies Criterion 4 of the NRC Policy Statement (Ref. 2). It is assumed in Reference 1 and can be considered risk significant.

(continued)

HATCH UNIT 2 B 3.6-69 REVISION 1

TABLE OF CONTENTS (continued)

B 3.6 CONTAINMENT SYSTEMS.............................................

B 3.6-1 B 3.6.1.1 Primary Containment............................................. B 3.6-1 B 3.6.1.2 Primary Containment Air Lock.............................................

B 3.6-6 B 3.6.1.3 Primary Containment Isolation Valves (PCIVs).........................

.......... B 3.6-13 B 3.6.1.4 Drywell Pressure.............................................

B 3.6-28 B 3.6.1.5 Drywell Air Temperature.............................................

B 3.6-30 B 3.6.1.6 Low-Low Set (LLS) Valves..............................................

B 3.6-33 B 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers.........

.... B 3.6-36 B 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers............................ B 3.6-41 B 3.6.2.1 Suppression Pool Average Temperature............................................. B 3.6-47 B 3.6.2.2 Suppression Pool Water Level.....................

......................... B 3.6-52 B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling................... B 3.6-55 B 3.6.2.4 Residual Heat Removal (RHR) Suppression Pool Spray...................... B 3.6-59 B 3.6.3.1 (Not used)..............................................

B 3.6-63 B 3.6.3.2 Primary Containment Oxygen Concentration.......................................

B 3.6-64 B 3.6.3.3 Drywell Cooling System Fans...................

........................... B 3.6-67 B 3.6.4.1 Secondary Containment..............................................

B 3.6-72 B 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)...................

............ B 3.6-78 B 3.6.4.3 Standby Gas Treatment (SGT) System.............................................

B 3.6-85 (continued)

HATCH UNIT 2 iv

PAM Instrumentation B 3.3.3.1 BASES LCO

6. Primarv Containment Isolation Valve (PCIV) Position (continued)

PCIV position is provided for verification of containment integrity. In the case of PCIV position, the important information is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each active PCIV in a containment penetration flow path, i.e., two total channels of PCIV position indication for a penetration flow path with two active valves. For containment penetrations with only one active PCIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient to redundantly verify the isolation status of each isolable penetration via indicated status of the active valve, as applicable, and prior knowledge of passive valve or system boundary status. If a penetration flow path is isolated, position indication for the PCIV(s) in the associated penetration flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flow path is not required to be OPERABLE. The indication for each PCIV consists of green and red indicator lights that illuminate to indicate whether the PCIV is fully open, fully closed, or in a mid-position. Therefore, the PAM specification deals specifically with this portion of the instrumentation channel.

7.. 8. (Not used)

9. Suppression Pool Water Temperature Suppression pool water temperature is a Type A variable provided to detect a condition that could potentially lead to containment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression pool water temperature (continued)

HATCH UNIT 1 B 3.3-63

PAM Instrumentation B 3.3.3.1 BASES LCO

6. Primarv Containment Isolation Valve (PCIV) Position (continued)

PCIV position is provided for verification of containment integrity. In the case of PCIV position, the important information is the isolation status of the containment penetration. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each active PCIV in a containment penetration flow path, i.e., two total channels of PCIV position indication for a penetration'flow path with two active valves. For containment penetrations with only one active PCIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient to redundantly verify the isolation status of each isolable penetration via indicated status of the active valve, as applicable, and prior knowledge of passive valve or system boundary status. If a penetration flow path is isolated, position indication for the PCIV(s) in the associated penetration flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flow path is not required to be OPERABLE. The.

indication for each PCIV consists of green and red indicator lights that illuminate to indicate whether the. PCIV is fully open, fully closed, or in a mid-position. Therefore, the PAM specification deals specifically with this portion of the instrumentation channel.

7.. 8. (Not used)

9. Suppression Pool Water Temperature Suppression pool water temperature is a Type A variable provided to detect a condition that could potentially lead to containment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression pool water temperature (continued)

HATCH UNIT 2 B 3.3-63 REVISION

Reactor Building-to-Suppression Chamber Vacuum Breakers B 3.6.1.7 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers BASES BACKGROUND The function of the reactor building-to-suppression chamber vacuum breakers is to relieve vacuum when primary containment depressurizes below reactor building pressure. If the drywell depressurizes below reactor building pressure, the negative differential pressure is mitigated by flow through the reactor building-to-suppression chamber vacuum breakers and through the suppression-chamber-to-drywell vacuum breakers. The design of the external (reactor building-to-suppression chamber) vacuum relief provisions consists of two vacuum breakers (a mechanical vacuum breaker and an air operated butterfly valve), located in series in each of two lines from the reactor building to the suppression chamber airspace. The butterfly valve is actuated by differential pressure. The mechanical vacuum breaker is self actuating and can be remotely operated for testing purposes. The two vacuum breakers in series must be closed to maintain a leak tight primary containment boundary.

A negative differential pressure across the drywell wall is caused by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, inadvertent primary containment spray actuation, and steam condensation in the event of a primary system rupture. Reactor building-to-suppression chamber vacuum breakers prevent an excessive negative differential pressure across the primary containment boundary. Cooling cycles result in minor pressure transients in the drywell, which occur slowly and are normally controlled by heating and ventilation equipment. Inadvertent spray actuation results in a more significant pressure transient and becomes important in sizing the external (reactor building-to-suppression chamber) vacuum breakers.

Increased differential pressure between the reactor building and the drywell can also be caused by operations which remove gas from the drywell. Such operations include inerting/de-inerting of the primary containment.

The external vacuum breakers are sized on the basis of the air flow from the secondary containment that is required to mitigate the depressurization transient and limit the maximum negative containment (drywell and suppression chamber) pressure to within design limits. The maximum depressurization rate is a function of the primary containment spray flow rate and temperature and the (continued)

HATCH UNIT 2 B 3.6-36

Suppression Chamber-to-Drywell Vacuum Breakers B 3.6.1.8 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers BASES BACKGROUND The function of the suppression chamber-to-drywell vacuum breakers is to relieve vacuum in the drywell. There are 12 internal vacuum breakers located on the vent header of the vent system between the drywell and the suppression chamber, which allow air and steam flow from the suppression chamber to the drywell when the drywell is at a negative pressure with respect to the suppression chamber.

Therefore, suppression chamber-to-drywell vacuum breakers prevent an excessive negative differential pressure across the wetwell drywell boundary. Each vacuum breaker is a self actuating valve, similar to a check valve, which can be remotely operated for testing purposes.

A negative differential pressure across the drywell wall is caused by rapid depressurization of the drywell. Events that cause this rapid depressurization are cooling cycles, inadvertent drywell spray actuation, and steam condensation from sprays or subcooled water reflood of a break in the event of a primary system rupture. Cooling cycles result in minor pressure transients in the drywell that occur slowly and are normally controlled by heating and ventilation equipment. Spray actuation or spill of subcooled water out of a break results in more significant pressure transients and becomes important in sizing the internal vacuum breakers.

Increased differential pressure between the suppression chamber and the drywell can also be caused by operations which add gas to the suppression chamber or remove gas from the drywell. Such operations include inerting/de-inerting of the primary containment.

In the event of a primary system rupture, steam condensation within the drywell results in the most severe pressure transient. Following a primary system rupture, air in the drywell is purged into the suppression chamber free airspace, leaving the drywell full of steam.

Subsequent condensation of the steam can be caused in two possible ways, namely, Emergency Core Cooling Systems flow from a recirculation line break, or drywell spray actuation following a loss of coolant accident (LOCA). These two cases cases determine the maximum depressurization rate of the drywell.

In addition, the waterleg in the Mark I Vent System downcomer is controlled by the drywell-to-suppression chamber differential (continued)

I HATCH UNIT 2 B 3.6-41

(Not used)

B 3.6.3.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 (Not used)

HATCH UNIT 2 B 3.6-63 REVISION

Primary Containment Oxygen Concentration B 3.6.3.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.2 Primary Containment Oxygen Concentration BASES BACKGROUND Boiling water reactors must be designed to withstand events that generate hydrogen either due to the zirconium metal water reaction in the core or due to radiolysis. The primary method to control hydrogen is to inert the primary containment. With the primary containment inert, that is, oxygen concentration < 4.0 volume percent (v/o), a combustible mixture cannot be present in the primary containment for any hydrogen concentration. An event that rapidly generates hydrogen from zirconium metal water reaction will result in excessive hydrogen in primary containment, but oxygen concentration will remain < 4.0 v/o and no combustion can occur. This LCO ensures that oxygen concentration does not exceed 4.0 v/o during operation in the applicable conditions.

I I

APPLICABLE SAFETY ANALYSES The Plant Hatch Individual Plant Examination (Ref. 1) assumes that the primary containment is inerted when a Design Basis Accident loss of coolant accident occurs. Thus, the hydrogen assumed to be released to the primary containment as a result of metal water reaction in the reactor core will not produce combustible gas mixtures in the primary containment.

I The primary containment oxygen concentration satisfies Criterion 4 of the NRC Policy Statement (Ref. 2). It is assumed in Reference 1 and can be considered risk significant.

LCO The primary containment oxygen concentration is maintained

< 4.0 v/o to ensure that an event that produces any amount of hydrogen does not result in a combustible mixture inside primary containment.

(continued)

HATCH UNIT 2 B 3.6-64 REVISION

Primary Containment Oxygen Concentration B 3.6.3.2 BASES (continued)

APPLICABILITY The primary containment oxygen concentration must be within the specified limit when primary containment is inerted, except as allowed by the relaxations during startup and shutdown addressed below.

The primary containment must be inert in MODE 1, since this is the condition with the highest probability of an event that could produce hydrogen.

Inerting the primary containment is an operational problem because it prevents containment access without an appropriate breathing apparatus. Therefore, the primary containment is inerted as late as possible in the plant startup and de-inerted as soon as possible in the plant shutdown. As long as reactor power is < 15% RTP, the potential for an event that generates significant hydrogen is low and the primary containment need not be inert. Furthermore, the probability of an event that generates hydrogen occurring within the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of a startup, or within the last 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months before a shutdown, is low enough that these windows," when the primary containment is not inerted, are also justified. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months time period is a reasonable amount of time to allow plant personnel to perform inerting or de-inerting.

ACTIONS Ami If oxygen concentration is 2 4.0 v/o at any time while operating in MODE 1, with the exception of the relaxations allowed during startup and shutdown, oxygen concentration must be restored to < 4.0 v/o within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is allowed when oxygen concentration is z 4.0 v/o because of the availability of other hydrogen mitigating systems (e.g., hydrogen recombiners) and the low probability and long duration of an event that would generate significant amounts of hydrogen occurring during this period.

B:1 If oxygen concentration cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, power must be reduced to s 15% RTP within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

(continued)

HATCH UNIT 2 B 3.6-65 REVISION I

Primary Containment Oxygen Concentration B 3.6.3.2 BASES (continued)

SURVEILLANCE REQUIREMENTS SR K63.2-The primary containment (drywell and suppression chamber) must be determined to be inert by verifying that oxygen concentration is

< 4.0 v/o. The 7 day Frequency is based on the slow rate at which oxygen concentration can change and on other indications of abnormal conditions (which would lead to more frequent checking by operators in accordance with plant procedures). Also, this Frequency has been shown to be acceptable through operating experience.

REFERENCES

1.

Edwin I. Hatch Nuclear Plants Units 1 and 2 Plant Hatch Individual Plant Examination (IPE), December 1992.

2.

NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

HATCH UNIT 2 B 3;6-66 REVISION I

Drywell Cooling System Fans B 3.6.3.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.3 Drywell Cooling System Fans BASES BACKGROUND The Drywell Cooling System (air side) ensures a uniformly mixed post accident primary containment atmosphere, thereby minimizing the potential for local hydrogen burns due to a pocket of hydrogen above the flammable concentration.

The Drywell Cooling System is designed to withstand a loss of coolant accident (LOCA) in post accident environments without loss of function. However, the system is not "environmentally qualified."

The system has eight subsystems consisting of recirculation fans, fan coil units, motors, controls, and ducting. However, due to the fact that the 2T47-B01 OA/B Units do not receive power from the diesel generators, they are not allowed to be used to meet the LCO requirements. Each of the six credited subsystems is sized to circulate 8000 scfm (for the 2T47-BO07A/B fans) or 25,000 scfm (for the 2T47-BOO8A/B and 2T47-BO09A/B fans). The Drywell Cooling System employs both forced circulation and natural circulation to ensure the proper mixing of hydrogen in primary containment. The recirculation fans provide the forced circulation to mix hydrogen while the fan coils provide the natural circulation by increasing the density through the cooling of the hot gases at the top of the drywell causing the cooled gases to gravitate to the bottom of the drywell. The six subsystems are initiated manually since flammability limits would not be reached until several days after a LOCA. Three of the subsystems are powered from one emergency power supply while the other three subsystems are powered from another emergency power supply.

Since each subsystem can provide 100% of the mixing requirements, the system will provide its design function with a worst case single active failure.

The Drywell Cooling System uses the Drywell Cooling System recirculating fans to mix the drywell atmosphere. The fan coil units and recirculation fans are automatically disengaged during a LOCA but may be restored to service manually by the operator. In the event of a loss of offsite power, all fan coil units, recirculating fans, and primary containment water chillers are transferred to the emergency diesels. The fan coil units and recirculating fans are started automatically from diesel power upon loss of offsite power.

(continued)

HATCH UNIT 2 B 3.6-67 REVISION I

Drywell Cooling System Fans B 3.6.3.3 BASES (continued)

APPLICABLE The Drywell Cooling System fans provide the capability for reducing SAFETY ANALYSES the local hydrogen concentration to approximately the bulk average concentration following a Design Basis Accident (DBA). The limiting DBA relative to hydrogen generation is a LOCA.

Hydrogen may accumulate in primary containment following a LOCA as a result of:

a.

A metal steam reaction between the zirconium fuel rod cladding and the reactor coolant; or

b.

Radiolytic decomposition of water in the Reactor Coolant System.

To evaluate the potential for hydrogen accumulation in primary containment following a LOCA, the hydrogen generation as a function of time following the initiation of the accident is calculated.

Conservative assumptions recommended by Reference 1 are used to maximize the amount of hydrogen calculated.

The Reference 2 calculations show that hydrogen assumed to be released to the drywell within 2 minutes following a DBA LOCA raises drywell hydrogen concentration to over 2.5 volume percent (v/o).

Natural circulation phenomena result in a gradient concentration difference of less then 0.5 v/o in the drywell and less than 0.1 v/o in the suppression chamber. Even though this gradient is acceptably small and no credit for mechanical mixing was assumed in the analysis, two Drywell Cooling System fans are required to be OPERABLE by this LCO. This will ensure the gradient concentration difference is small.

The Drywell Cooling System fans satisfy Criterion 3 of the NRC Policy Statement (Ref. 3).

LCO Two Drywell Cooling System fans must be OPERABLE to ensure operation of at least one fan in the event of a worst case single active failure. Each of these fans must be powered from an independent safety related bus. The 2T47-B007A and B, B008 A and B, and B009 A and B fans shall be used to meet this requirement. In addition, only the recirculation fan portion of the system must be OPERABLE; the cooler portion does not need to be OPERABLE. Operation with at (continued)

HATCH UNIT 2 B 3.6-68 REVISION I

Drywell Cooling System Fans B 3.6.3.3 BASES LCO least one fan provides the capability of controlling the bulk hydrogen (continued) concentration in primary containment without exceeding the flammability limit.

APPLICABILITY In MODES 1 and 2, the two Drywell Cooling System fans ensure the capability to prevent localized hydrogen concentrations above the flammability limit of 4.0 v/o in drywell, assuming a worst case single active failure.

In MODE 3, both the hydrogen production rate and the total hydrogen produced after a LOCA would be less than that calculated for the DBA LOCA. Also, because of the limited time in this MODE, the probability of an accident requiring the Drywell Cooling System fans is low.

Therefore, the Drywell Cooling System fans are not required in MODE 3.

In MODES 4 and 5, the probability and consequences of a LOCA are reduced due to the pressure and temperature limitations in these MODES. Therefore, the Drywell Cooling System fans are not required in these MODES.

ACTIONS A.1 With one required Drywell Cooling System fan inoperable, the inoperable fan must be restored to OPERABLE status within 30 days.

In this condition, the remaining OPERABLE fan is adequate to perform the hydrogen mixing function. However, the overall reliability is reduced because a single failure in the OPERABLE fan could result in reduced hydrogen mixing capability. The 30 day Completion Time is based on the availability of the second fan, the low probability of the occurrence of a LOCA that would generate hydrogen in amounts capable of exceeding the flammability limit, the amount of time available after the event for operator action to prevent exceeding this limit, and the availability of natural circulation to maintain the atmosphere mixed.

(continued)

HATCH UNIT 2 B 3.6-69 REVISION I

Drywell Cooling System Fans B 3.6.3.3 BASES ACTIONS A.1 (continued)

Required Action A.1 has been modified by a Note indicating that the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when one required Drywell Cooling System fan is inoperable. This allowance is provided because of the low probability of the occurrence of a LOCA that would generate hydrogen in amounts capable of exceeding the flammability limit, the low probability of the failure of the OPERABLE fan, and the amount of time available after a postulated LOCA for operator action to prevent exceeding the flammability limit.

B.1 With two Drywell Cooling System fans inoperable, one fan must be restored to OPERABLE status within 7 days. Seven days is a reasonable time to allow two Drywell Cooling System fans to be inoperable because the hydrogen mixing function is maintained via natural circulation and because of the low probability of the occurrence of a LOCA that would generate hydrogen in amounts capable of exceeding the flammability limit.

C.1 If any Required Action and associated Completion Time cannot be 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 at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . 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.

SURVEILLANCE SR 3.6.3.3.1 REQUIREMENTS Operating each required Drywell Cooling System fan for 2 15 minutes ensures that each subsystem is OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action.

(continued)

HATCH UNIT 2 B 3.6-70 REVISION I

Drywell Cooling System Fans B 3.6.3.3 BASES SURVEILLANCE SR 3.6.3.3.1 (continued)

REQUIREMENTS The 92 day Frequency is consistent with the Inservice Testing Program Frequencies, operating experience, the known reliability of the fan motors and controls, and the two redundant fans available.

REFERENCES

1.

Regulatory Guide 1.7, Revision 0.

2.

FSAR, Section 6.2.5.

3.

NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

HATCH UNIT 2 B 3.6-71 REVISION I

Secondary Containment B 3.6.4.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.1 Secondary Containment BASES BACKGROUND The function of the secondary containment is to contain, dilute, and hold up fission products that may leak from primary containment following a Design Basis Accident (DBA). In conjunction with operation of the Standby Gas Treatment (SGT) System and closure of certain valves whose lines penetrate the secondary containment, the secondary containment is designed to reduce the activity level of the fission products prior to release to the environment and to isolate and contain fission products that are released during certain operations that take place inside primary containment, when primary containment is not required to be OPERABLE, or that take place outside primary containment.

The secondary containment is a structure that completely encloses the primary containment and those components that may be postulated to contain primary system fluid. This structure forms a control volume that serves to hold up and dilute the fission products.

It is possible for the pressure in the control volume to rise relative to the environmental pressure (e.g., due to pump and motor heat load additions). The secondary containment encompasses three separate zones: the Unit 1 reactor building (Zone I), the Unit 2 reactor building (Zone II), and the common refueling floor (Zone ll). The secondary containment can be modified to exclude the Unit 1 reactor building (Zone I) provided the following requirements are met:

a.

Unit 1 Technical Specifications do not require OPERABILITY of Zone l;

b.

All hatches separating Zone III from Zone I are closed and sealed; and

c.

At least one door in each access path separating Zone IlIl from Zone I is closed.

Similarly, other zones can be excluded from the secondary containment OPERABILITY requirement during various plant operating conditions with the appropriate controls. For example, during Unit 2 shutdown operations, the secondary containment can be modified to exclude the Unit 2 reactor building (Zone II) (either alone or in combination with excluding Zone I as described above) provided the following requirements are met:

(continued)

HATCH UNIT 2 B 3.6-72 REVISION I

Secondary Containment B 3.6.4.1 BASES BACKGROUND (continued)

a.

Unit 2 is not conducting operations with a potential for draining the reactor vessel (OPDRV);

b.

All hatches separating Zone III from Zone II are closed and sealed; and

c.

At least one door in each access path separating Zone IlIl from Zone II is closed.

To prevent ground level exfiltration while allowing the secondary containment to be designed as a conventional structure, the secondary containment requires support systems to maintain the control volume pressure at less than the external pressure.

Requirements for these systems are specified separately in LCO 3.6.4.2, Secondary Containment Isolation Valves (SCIVs),t and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System." When one or more zones are excluded from secondary containment, the specific requirements for the support systems will also change (e.g., securing particular SGT or drain isolation valves).

APPLICABLE SAFETY ANALYSES There are two principal accidents for which credit is taken for secondary containment OPERABILITY. These are a loss of coolant accident (LOCA) (Ref. 1) and a fuel handling accident inside secondary containment (Ref. 2). The secondary containment performs no active function in response to either of these limiting events; however, its leak tightness is required to ensure that the release of radioactive materials from the primary containment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis and that fission products entrapped within the secondary containment structure will be treated by the Unit 1 and Unit 2 SGT Systems prior to discharge to the environment.

Postulated LOCA leakage paths from the primary containment into secondary containment include those into both the reactor building and refueling floor zones (e.g., drywell head leakage).

Secondary containment satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).

LCO An OPERABLE secondary containment provides a control volume into which fission products that bypass or leak from primary containment, or are released from the reactor coolant pressure boundary (continued)

HATCH UNIT 2 B 3.6-73 REVISION I

Secondary Containment B 3.6.4.1 BASES LCO (continued) components located in secondary containment, can be diluted and processed prior to release to the environment. For the secondary containment to be considered OPERABLE, it must have adequate leak tightness to ensure that the required vacuum (0.20 inch of vacuum) can be established and maintained. The secondary containment boundary required to be OPERABLE is dependent on the operating status of both units, as well as the configuration of doors, hatches, refueling floor plugs, SCIVs, and available flow paths to SGT Systems.

The required boundary encompasses the zones which can be postulated to contain fission products from accidents required to be considered for the condition of each unit, and furthermore, must include zones not isolated from the SGT subsystems being credited for meeting LCO 3.6.4.3. Allowed configurations, associated SGT subsystem requirements, and associated SCIV requirements are detailed in the Technical Requirements Manual (Ref. 3).

APPLICABILITY In MODES 1, 2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to secondary containment (the reactor building zone and potentially the refueling floor zone).

Therefore, secondary containment OPERABILITY is required during the same operating conditions that require primary containment OPERABILITY.

In MODES 4 and 5, the probability and consequences of the LOCA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining secondary containment OPERABLE is not required in MODE 4 or 5 to ensure a control volume, except for other situations for which significant releases of radioactive material can be postulated, such as during OPDRVs, during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment. (Note, moving irradiated fuel assemblies in the secondary containment may also occur in MODES 1, 2, and 3.)

Since CORE ALTERATIONS and movement of irradiated fuel assemblies are only postulated to release radioactive material to the refueling floor zone, the secondary containment configuration may consist of only Zone III during these conditions. Similarly, during OPDRVs while in MODE 4 (vessel head bolted) the release of radioactive materials is only postulated to the associated reactor building, the secondary containment configuration may consist of only Zone II.

(continued)

HATCH UNIT 2 B 3.6-74 REVISION I

Secondary Containment B 3.6.4.1 BASES (continued)

ACTIONS A.1 If secondary containment is inoperable, it must be restored to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining secondary containment during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring secondary containment OPERABILITY) occurring during periods where secondary containment is inoperable is minimal.

B.1 and B.2 If secondary containment cannot be restored to OPERABLE status within the required Completion Time, 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 at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

C.1. C.2. and C.3 Movement of irradiated fuel assemblies in the secondary containment, CORE ALTERATIONS, and OPDRVs can be postulated to cause fission product release to the secondary containment. In such cases, the secondary containment is the only barrier to release of fission products to the environment. CORE ALTERATIONS and movement of irradiated fuel assemblies must be immediately suspended if the secondary containment is inoperable.

Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position. Also, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

Required Action C.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, (continued)

HATCH UNIT 2 B 3.6-75 T REVISION I

Secondary Containment B 3.6.4.1 BASES ACTIONS C.1. C.2, and C.3 (continued) inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.6.4.1.1 and SR 3.6.4.1.2 REQUIREMENTS Verifying that secondary containment equipment hatches and one access door in each access opening are closed ensures that the infiltration of outside air of such a magnitude as to prevent maintaining the desired. negative pressure does not occur. Verifying that all such openings are closed provides adequate assurance that exfiltration from the secondary containment will not occur. SR 3.6.4.1.1 also requires equipment hatches to be sealed. In this application, the term "sealed has no connotation of leak tightness. Maintaining secondary containment OPERABILITY requires verifying one door in the access opening is closed. An access opening contains one inner and one outer door. The intent is not to breach the secondary containment at any time when secondary containment is required. This is achieved by maintaining the inner or outer portion of the barrier closed at all times. However, all secondary containment access doors are normally kept closed, except when the access opening is being used for entry and exit or when maintenance is being performed on an access opening. When the secondary containment configuration excludes Zone I and/or Zone II, these SRs also include verifying the hatches and doors separating the common refueling floor zone from the reactor building(s). The 31 day Frequency for these SRs has been shown to be adequate, based on operating experience, and is considered adequate in view of the other indications of door and hatch status that are available to the operator.

SR 3.6.4.1.3 and SR 3.6.4.1.4 The Unit 1 and Unit 2 SGT Systems exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment. To ensure that all fission products are treated, SR 3.6.4.1.3 verifies that the appropriate SGT System(s) will rapidly establish and maintain a negative pressure in the secondary containment. This is confirmed by demonstrating that the required SGT subsystem(s) will draw down the secondary containment to

> 0.20 inch of vacuum water gauge in s 120 seconds. This cannot be accomplished if the secondary containment boundary is not intact.

SR 3.6.4.1.4 demonstrates that the required SGT subsystem(s) can (continued)

HATCH UNIT 2 B 3.6-76 REVISION I

Secondary Containment B 3.6.4.1

BASES SURVEILLANCE SR 3.6.4.1.3 and SR 3.6.4.1.4 (continued)

REQUIREMENTS maintain 2 0.20 inch of vacuum water gauge for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at a flow rate s 4000 cfm for each SGT subsystem. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months test period allows secondary containment to be in thermal equilibrium at steady state conditions. Therefore, these two tests are used to ensure secondary containment boundary integrity. Since these SRs are secondary containment tests, they need not be performed with each SGT subsystem. The SGT subsystems are tested on a STAGGERED TEST BASIS, however, to ensure that in addition to the requirements of LCO 3.6.4.3, each SGT subsystem or combination of subsystems will perform this test. The number of SGT subsystems and the required combinations are dependent on the configuration of the secondary containment and are detailed in the Technical Requirements Manual (Ref. 3). The Note to SR 3.6.4.1.3 and SR 3.6.4.1.4 specifies that the number of required SGT subsystems be one less than the number required to meet LCO 3.6.4.3, "Standby Gas Treatment (SGT) System," for the given configuration. The 24 month Frequency, on a STAGGERED TEST BASIS,Iof.

SRs 3.6.4.1.3 and 3.6.4.1.4 is also based on a review of the surveillance test history and Reference 5.

REFERENCES

1.

FSAR, Section 15.1.39.

2.

FSAR, Section 15.1.41.

3.

Technical Requirements Manual.

4.

NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

5.

NRC Safety Evaluation Report for Amendment 174.

HATCH UNIT 2 B 3.6-77 REVISION I

SCIVs B 3.6.4.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)

BASES BACKGROUND The function of the SCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs). Secondary containment isolation within the time limits specified for those isolation

-valves designed to close automatically ensures that fission products that leak from primary containment following a DBA, or that are released during certain operations when primary containment is not required to be OPERABLE or take place outside primary containment, are maintained within the secondary containment boundary.

The OPERABILITY requirements for SCIVs help ensure that an adequate secondary containment boundary is maintained during and after an accident by minimizing potential paths to the environment.

These isolation devices consist of either passive devices or active (automatic) devices. Manual valves, de-activated automatic valves secured in their closed position, check valves with flow through the valve secured, and blind flanges are considered passive devices.

Automatic SCIVs close on a secondary containment isolation signal to establish a boundary for untreated radioactive material within secondary containment folloWing a DBA or other accidents.

Other penetrations are isolated by the use of valves in the closed position or blind flanges.

APPLICABLE SAFETY ANALYSES The SCIVs must be OPERABLE to ensure the secondary containment barrier to fission product releases is established. The principal accidents for which the secondary containment boundary is required are a loss of coolant accident (Ref. 1) and a fuel handling accident inside secondary containment (Ref. 2). The secondary containment performs no active function in response to either of these limiting events, but the boundary established by SCIVs is required to ensure that leakage from primary containment is processed by the Standby Gas Treatment (SGT) System before being released to the environment.

Maintaining SCIVs OPERABLE with isolation times within limits ensures that fission products will remain trapped inside secondary (continued)

HATCH UNIT 2 B 3.6-78 REVISION I

SC!Vs B 3.6.4.2 BASES APPLICABLE containment so that they can be treated by the SGT System prior to SAFETY ANALYSES discharge to the environment.

(continued)

SCIVs satisfy Criterion 3 of the NRC Policy Statement (Ref. 4).

LCO SCIVs form a part of the secondary containment boundary. The SCIV safety function is related to control of offsite radiation releases resulting from DBAs.

The power operated isolation valves are considered OPERABLE when their isolation times are within limits and the valves actuate on an automatic isolation signal. The valves covered by this LCO, along with their associated stroke times, are listed in Reference 3.

The normally closed isolation valves or blind flanges are considered OPERABLE when manual valves are closed, or open in accordance with appropriate administrative controls, automatic SCIVs are de-activated and secured in their closed position, and blind flanges are in place. These passive isolation valves or devices are listed in Reference 3.

The SCIVs required to be OPERABLE are dependent on the configuration of the secondary containment (which is dependent on the operating status of both units, as well as the configuration of doors, hatches, refueling floor plugs, and available flow paths to SGT Systems). The required boundary encompasses the zones which can be postulated to contain fission products from accidents required to be considered for the condition of each unit, and furthermore, must include zones not isolated from the SGT subsystems being credited for meeting LCO 3.6.4.3, "Standby Gas Treatment (SGT) System.,

The required SCIVs are those in penetrations communicating with the zones required for secondary containment OPERABILITY and are detailed in Reference 3.

APPLICABILITY In MODES 1, 2, and 3, a LOCA could lead to a fission product release to the primary containment that leaks to the secondary containment.

Therefore, the OPERABILITY of SCIVs is required.

In MODES 4 and 5, the probability and consequences of a LOCA are reduced due to pressure and temperature limitations in these MODES. Therefore, maintaining SCIVs OPERABLE is not required in (continued)

HATCH UNIT 2 B 3.6-79 REVISION I

SCIVs B 3.6.4.2 BASES APPLICABILITY MODE 4 or 5, except for other situations under which significant (continued) radioactive releases can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment. (Note: Moving irradiated fuel assemblies in the secondary containment may also occur in MODES 1, 2, and 3.)

ACTIONS The ACTIONS are modified by three Notes. The first Note allows penetration flow paths to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator, who is in continuous communication with the control room, at the controls of the isolation device. In this way, the penetration can be rapidly isolated when a need for secondary containment isolation is indicated.

The second Note provides clarification that for the purpose of this LCO separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable SCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SCIVs are governed by subsequent Condition entry and application of associated Required Actions.

The third Note ensures appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable SCIV.

A.1 and A.2 In the event that there are one or more penetration flow paths with one SCIV inoperable, the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic SCIV, a closed manual valve, and a blind flange. For penetrations isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available device to secondary containment. The Required Action must be completed within the 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time. The specified time period is reasonable considering the time required to (continued)

HATCH UNIT 2 B 3.6-80 REVISION I

SCIVs B 3.6.4.2 BASES ACTIONS A.1 and A.2 (continued) isolate the penetration, and the probability of a DBA, which requires the SCIVs to close, occurring during this short time is very low.

For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that secondary containment penetrations required to be isolated following an accident, but no longer capable of being automatically isolated, will be in the isolation position should an event occur. The Completion Time of once per 31 days is appropriate because the isolation devices are operated under administrative controls and the probability of their misalignment is low. This Required Action does not require any testing or device manipulation. Rather, it involves verification that the affected penetration remains isolated.

Required Action A.2 is modified by a Note that applies to devices located in high radiation areas and allows them to be verified closed by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Therefore, the probability of misalignment once they have been verified to be in the proper position, is low.

B.1 With two SCIVs in one or more penetration flow paths inoperable, the affected penetration flow path must be isolated within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The method of isolation must include the use of at least one isolation.

barrier that cannot be adversely affected by a single active failure.

Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable considering the time required to isolate the penetration and the probability of a DBA, which requires the SCIVs to close, occurring during this short time, is very low.

C.1 and C.2 If any Required Action and associated Completion Time of Condition A or B cannot be 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 at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are (continued)

HATCH UNIT 2 B 3.6-81 REVISION I

SCIVs B 3.6.4.2 BASES ACTIONS C.1. and C.2.(continued) reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

D.1, D.2. and D.3 If any Required Action and associated Completion Time.of Condition A or B are not met, the plant must be placed in a condition in which the LCO does not apply. If applicable, CORE ALTERATIONS and the movement of irradiated fuel assemblies in the secondary containment must be immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must be immediately initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

Required Action D.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving fuel while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations.

Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.6.4.2.1 REQUIREMENTS This SR verifies that each secondary containment manual isolation valve and blind flange that is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the secondary containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it involves verification that those isolation devices in secondary containment that are capable of being mispositioned are in the correct position.

Since these isolation devices are readily accessible to personnel during normal operation and verification of their position is relatively (continued)

HATCH UNIT 2 B 3.6-82 REVISION I

SCIVs B 3.6.4.2 BASES SURVEILLANCE SR 3.6.4.2.1 (continued)

REQUIREMENTS easy, the 31 day Frequency was chosen to provide added assurance that the isolation devices are in the correct positions.

Two Notes have been added to this SR. The first Note applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these isolation devices, once they have been verified to be in the proper position, is low.

A second Note has been included to clarify that SCIVs that are open under administrative controls are not required to meet the SR during the time the SCIVs are open.

SR 3.6.4.2.2 Verifying that the isolation time of each power operated and each automatic SCIV is within limits is required to demonstrate OPERABILITY. The isolation time test ensures that the SCIV will isolate in a time period less than or equal to that assumed in the safety analyses. The Frequency of this SR was developed based upon engineering judgment and the similarity to PCIVs.

SR 3.6.4.2.3 Verifying that each automatic SCIV closes on a secondary containment isolation signal is required to prevent leakage of radioactive material from secondary containment following a DBA or other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position on a secondary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.2.5 overlaps this SR to provide complete testing of the safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. The 24 month Frequency is based on a review of the surveillance test history and Reference 5.

(continued)

HATCH UNIT 2 B 3.6-83 REVISION I

SCIVs B 3.6.4.2

. BASES (continued)

REFERENCES

1.

FSAR, Section 15.1.39.

2.

FSAR, Section 15.1.41.

3.

Technical Requirements Manual.

4.

NRC No.93-102, Final Policy Statement on Technical Specification Improvements,' July 23, 1993.

5.

NRC Safety Evaluation Report for Amendment 174.

HATCH UNIT 2 B 3.6-84 REVISION I

SGT System B 3.6.4.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.3 Standby Gas Treatment (SGT) System BASES BACKGROUND The SGT System is required by 10 CFR 50, Appendix A, GDC 41, Containment Atmosphere Cleanup" (Ref. 1). The function of the SGT System is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a Design Basis Accident (DBA) are filtered and adsorbed prior to exhausting to the environment.

The Unit 1 and Unit 2 SGT Systems each consists of two fully redundant subsystems, each with its own set of dampers, charcoal filter train, and controls. The Unit 1 SGT subsystems' ductwork is separate from the inlet to the filter train to the discharge of the fan.

The rest of the ductwork is common. The Unit 2 SGT subsystems' ductwork is separate except for the suction from the drywell and torus, which is common (however, this suction path is not required for subsystem OPERABILITY).

Each charcoal filter train consists of (components listed in order of the direction of the air flow):

a.

A demister or moisture separator;

b.

An electric heater;

c.

A prefilter;

d.

A high efficiency particulate air (HEPA) filter;

e.

Two charcoal adsorbers for Unit 1 subsystems and one charcoal adsorber for Unit 2 subsystems;

f.

A second HEPA filter; and

g.

An axial vane fan for Unit 1 subsystems and a centrifugal fan for Unit 2 subsystems.

The sizing of the SGT Systems equipment and components is based on the results of an infiltration analysis, as well as an exfiltration analysis of the secondary containment. The internal pressure of the SGT Systems boundary region is maintained at a negative pressure when the system is in operation, to conservatively ensure zero (continued)

HATCH UNIT 2 B 3.6-85 REVISION I

SGT System B 3.6.4.3 BASES BACKGROUND exfiltration of air from the building when exposed to winds as high as (continued) 31 mph.

The demister is provided to remove entrained water in the air, while the electric heater reduces the relative humidity of the airstream to

< 70% (Refs. 2 and 3). The prefilter removes large particulate matter, while the HEPA filter removes fine particulate matter and protects the charcoal from fouling. The charcoal adsorbers remove gaseous elemental iodine and organic iodides, and the final HEPA filter collects any carbon fines exhausted from the charcoal adsorber..

The Unit 1 and Unit 2 SGT Systems automatically start and operate in response to actuation signals indicative of conditions or an accident that could require operation of the system. Following initiation, all required charcoal filter train fans start. Upon verification that the required subsystems are operating, the redundant required subsystem is normally shut down.

APPLICABLE The design basis for the Unit 1 and Unit 2 SGT Systems is to SAFETY ANALYSES mitigate the consequences of a loss of coolant accident and fuel handling accidents (Refs. 2, 3, 4, and 5). For all events analyzed, the SGT Systems are shown to be automatically initiated to reduce, via filtration and adsorption, the radioactive material released to the environment.

The SGT System satisfies Criterion 3 of the NRC Policy Statement (Ref. 7).

LCO Following a DBA, a minimum number of SGT subsystems are required to maintain the secondary containment at a negative pressure with respect to the environment and to process gaseous releases. Meeting the LCO requirements for OPERABLE subsystems ensures operation of the minimum number of SGT subsystems in the event of a single active failure. The required number of SGT subsystems is dependent on the configuration required to meet LCO 3.6.4.1, "Secondary Containment.' For secondary containment OPERABILITY consisting of all three zones, the required number of SGT subsystems is four. With secondary containment OPERABILITY consisting of one reactor building and the common refueling floor zones, the required number of SGT subsystem is three. Allowed (continued)

HATCH UNIT 2 B 3.6-86 REVISION I

SGT System B 3.6.4.3 BASES LCO configurations and associated SGT subsystem requirements are (continued) detailed in the Technical Requirements Manual (Ref. 6).

In addition, with secondary containment in modified configurations, the SGT System valves to excluded zone(s) are not included as part of SGT System OPERABILITY (i.e., the valves may be secured closed and are not required to open on an actuation signal).

APPLICABILITY In MODES 1, 2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to secondary containment.

Therefore, Unit 1 and Unit 2 SGT Systems OPERABILITY are required during these MODES.

In MODES 4 and 5, the probability and consequences of a LOCA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SGT Systems in OPERABLE status is not required in MODE 4 or 5, except for other situations under which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), during CORE ALTERATIONS, or during movement of irradiated fuel assemblies in the secondary containment.

ACTIONS The Actions are modified by a Note to indicate that when both Unit 1 SGT subsystems are placed in an inoperable status for inspection of the Unit 1 hardened vent rupture disk, entry into associated Conditions and Required Actions may be delayed for up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , provided both Unit 2 SGT subsystems are OPERABLE. Upon completion of the inspection or expiration of the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance, the Unit 1 SGT subsystems must be returned to OPERABLE status or the applicable Conditions entered and Required Actions taken. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance is based upon precluding a dual unit shutdown to perform the inspection, yet minimizing the time both Unit 1 SGT subsystems are inoperable.

A.1 and B.1 With one required Unit 1 or Unit 2 SGT subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status. In this condition, the remaining required OPERABLE SGT subsystems are adequate to perform the required radioactivity release control function.

However, the overall system reliability is reduced because a single (continued)

HATCH UNIT 2 B 3.6-87 REVISION I

SGT System B 3.6.4.3 BASES ACTIONS A.1 and B.1 (continued) failure in one of the remaining required OPERABLE subsystems could result in the radioactivity release control function not being adequately performed. The 7 and 30 day Completion Times are based on consideration of such factors as the availability of the OPERABLE redundant SGT subsystems and the low probability of a DBA occurring during this period. Additionally, the 30 day Completion Time of Required Action A.1 is based on three remaining OPERABLE SGT subsystems, of which two are Unit 2 subsystems, and the secondary containment volume in the Unit 1 reactor building being open to the common refueling floor where the two Unit 2 SGT subsystems can readily provide rapid drawdown of vacuum. Testing and analysis has shown that in this configuration, even with an additional single failure (which is not necessary to assume while in ACTIONS) the secondary containment volume may be drawn to a vacuum in the time required to support assumptions of analyses.

C.1 and C.2 If the SGT subsystem cannot be restored to OPERABLE status within the required Completion Time in MODE 1, 2, or 3, 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 at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

In the event that a Unit 1 SGT subsystem is the one not restored to OPERABLE status as required by Required Action A.1 or B.1, and:

1.

All three zones are required for secondary containment OPERABILITY; and

2.

Unit 1 is shutdown with its Technical Specifications not requiring secondary containment OPERABILITY (i.e., not handling irradiated fuel, performing CORE ALTERATIONS, or conducting OPDRV),

operation of Unit 2 can continue provided that the Unit 1 reactor building zone is isolated from the remainder of secondary containment and the SGT System. In this modified secondary containment configuration, only three SGT subsystems are required to be OPERABLE to meet LCO 3.6.4.3, and no limitation is applied to (continued)

HATCH UNIT 2 B 3.6-88 REVISION I

SGT System B 3.6.4.3 BASES ACTIONS C.1 and C.2 (continued) the inoperable Unit 1 SGT subsystem. This in effect is an alternative to restoring the inoperable Unit 1 SGT subsystem, i.e., shut down Unit 1 and isolate its reactor building zone from secondary containment and SGT System.

D.1, D.2.1, D.2.2, and D.2.3 During movement of irradiated fuel assemblies in the secondary containment, during CORE ALTERATIONS, or during OPDRVs, when Required Action A.1 or B.1 cannot be completed within the required Completion Time, the remaining required OPERABLE SGT subsystems should immediately be placed in operation. This action ensures that the remaining subsystems are OPERABLE, that no failures that could prevent automatic actuation have occurred, and that any other failure would be readily detected.

An alternative to Required Action D.1 is to immediately suspend activities that represent a potential for releasing radioactive material to the secondary containment, thus placing the plant in a condition that minimizes risk. If applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies must immediately be suspended. Suspension of these activities must not preclude completion of movement of a component to a safe position. Also, if applicable, actions must immediately be initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

The Required Actions of Condition D have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

E.1 If two or more required SGT subsystems are inoperable in MODE 1, 2 or 3, the Unit 1 and Unit 2 SGT Systems may not be capable of supporting the required radioactivity release control function.

Therefore, LCO 3.0.3 must be entered immediately.

(continued)

HATCH UNIT 2 B 3.6-89 REVISION I

SGT System B 3.6.4.3 BASES ACTIONS F.1, F.2, and F.3 (continued)

When two or more required SGT subsystems are inoperable, if applicable, CORE ALTERATIONS and movement of irradiated fuel assemblies in secondary containment must immediately be suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must immediately be initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

Required Action F.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.6.4.3.1 REQUIREMENTS Operating each required Unit 1 and Unit 2 SGT subsystem for 2 10 continuous hours ensures that they are OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. Operation with the heaters on for 2 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA filters. The 31 day Frequency was developed in consideration of the known reliability of fan motors and controls and the redundancy available in the system.

SR 3.6.4.3.2 This SR verifies that the required Unit 1 and Unit 2 SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.

(continued)

HATCH UNIT 2 B 3.6-90 REVISION I

Edwin I. Hatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen and Oxygen Monitors Using the Consolidated Line Item Improvement Process FNP Marked-up and Clean Typed TS and Bases Pages

TABLE OF CONTENTS 3.4 3.4.1 3.4.2 3.4.3 3.4.4 3.4.5 3.4.6 3.4.7 3.4.8 3.4.9 3.4.10 3.4.11 3.4.12 3.4.13 3.4.14 3.4.15 3.4.16 3.5 3.5.1 3.5.2 3.5.3 3.5.4 3.5.5 3.5.6 REACTOR COOLANT SYSTEM (RCS)...............................................

3.4.1-1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits...............................................

3.4.1-1 RCS Minimum Temperature for Criticality...................................... 3.4.2-1 RCS Pressure and Temperature (PIT) Limits................................. 3.4.3-1 RCS Loops -MODES 1 and 2...............................................

3.4.4-1 RCS Loops-MODE 3...............................................

3.4.5-1 RCS Loops-MODE 4...............................................

3.4.6-1 RCS Loops-MODE 5, Loops Filled............................................. 3.4.7-1 RCS Loops-MODE 5, Loops Not Filled....................................... 3.4.8-1 Pressurizer...............................................

3.4.9-1 Pressurizer Safety Valves...............................................

3.4.10-1 Pressurizer Power Operated Relief Valves (PORVs)..................... 3.4.11-1 Low Temperature Overpressure Protection (LTOP) System.......... 3.4.12-1 RCS Operational LEAKAGE...............................................

3.4.13-1 RCS Pressure Isolation Valve (PIV) Leakage................................. 3.4.14-1 RCS Leakage Detection Instrumentation....................................... 3.4.15-1 RCS Specific Activity...............................................

3.4.16-1 EMERGENCY CORE COOLING SYSTEMS (ECCS)............................ 3.5.1-1 Accumulators 3.5.1-1 ECCS -

Operating

.............................. 3.5.2-1 ECCS-Shutdown

............................... 3.5.3-1 Refueling Water Storage Tank (RWST) 3.5.4-1 Seal Injection Flow

.............................. 3.5.5-1 ECCS Recirculation Fluid pH Control System..

3.5.f6-1 3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6 3.6.7 3.6.8 3.6.9 3.7 3.7.1 3.7.2 l DELETED CONTAINMENT SYSTEMS.................................

3.6.1-1 Containment

.3.6.1-1 Containment Air Locks.

3.6.2-1 Containment Isolation Valves

.3.6.3-1 Containment Pressure

.3.6.4-1 Containment Air Temperature.

3.6.5-1 Containment Spray and Cooling Systems................................. 3.6.6-1 I Hydroen Recooibiners................. /..........................

.3.6.7-1 Hydrogen Mixing System (HMS) 3.6.8-1 Reactor Cavity Hydrogen Dilution System 3.6.9-1 PLANT SYSTEMS...

3.7.1-1 Main Steam Safety Valves (MSSVs)...

3.7.1-1 Main Steam Isolation Valves (MSIVs)...

3.7.2-1 Farley Units 1 and 2 ii Amendment No. 146 (Unit 1)

Amendment No. 137 (Unit 2)

PAM Instrumentation 3.3.3 3.3 INSTRUMENTATION 3.3.3 Post Accident Monitoring (PAM) Instrumentation LCO 3.3.3 APPLICABILITY:

The PAM instrumentation for each Function in Table 3.3.3-1 shall be OPERABLE.

MODES 1, 2, and 3.

ACTIONS

-NOTE=S-----

1.

LCO 3.0.4 is not applicable.

2.

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more Functions A.1 Restore required channel 30 days with one required to OPERABLE status.

channel inoperable.

B.

Required Action and B.1 Initiate action in Immediately associated Completion accordance with Time of Condition A not Specification 5.6.8.

met.

C.

OTE----

C.1 Restore one channel to 7 days Not a icable to OPERABLE status.

hyd gen monit c annels.

One or more Functions with two required channels inoperable.

Farley Units 1 and 2 3.3.3-1 Amendment No. 146 (Unit 1)

Amendment No. 137 (Unit 2)

PAM Instrumentation 3.3.3 SURVEILLANCE REQUIREMENTS

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

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

SURVEILLANCE FREQUENCY SR 3.3.3.1 Perform CHANNEL CHECK for each required 31.days instrumentation channel that is normally energized.

SR 3.3.3.2 Perform CHANNEL CALIBRATION.

18 months Farley Units 1 and 2 3.3.3-2 Amendment No. 146 (Unit 1)

Amendment No. 137 (Unit 2)

PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 1 of 1)

Post Accident Monitoring Instrumentation FUNCTION REQUIRED CHANNELS CONDITION REFERENCED D

FROM REQUIRE ACTION 1

1. RCS Hot Leg Temperature (Wide Range)

2. RCS Cold Leg Temperature (Wide Range)

3. RCS Pressure (Wide Range)

4. Steam Generator (SG) Water Level (Wide or Narrow Range)

5. Refueling Water Storage Tank Level

6. Containment Pressure (Narrow Range)

7. Pressurizer Water Level

8. Steam Line Pressure

9. Auxiliary Feedwater Flow Rate

10. RCS Subcooling Margin Monitor

11. Containment Water Level (Wide Range)

12. Core Exit Temperature - Quadrant 1

13. Core Exit Temperature - Quadrant 2

14. Core Exit Temperature - Quadrant 3

15. Core Exit Temperature - Quadrant 4

16. Reactor Vessel Level Indicating System

17. Condensate Storage Tank Level 18.1 Hyd faen M *fors i',

19/Containment Area Radiation (High Range) 2 2

2 2/SG 2

2 2

2/SG 2

2 2

2(a) 2(a) 2(a) 2(a) 2 2

95E

/

2 I--,"

X,,

2 F-9

) A channel consists of two core exit thermocouples.

I DELETED Farley Units 1 and 2 3.3.3-3 Amendment No. 146 (Unit 1)

Amendment No. 137 (Unit 2)

DELETED Hydrogen Recombiners 3.6.7 3.6 CONTAINMEN YSTEMS 3.6.7 Hydroge ecombiners LCO 3.7 Two hydrogen reco iners shall be OPERABLE.

APPLICABILITY:

MODES n 2.

ACTIONS CONDITI REQUIRE/ACTION COMPLETION TIME A.

One hy ogen A.1

--NOTE-----

reco iner inoperable.

L 3.0.4 is not applicable.

Restore hydrogen 30 days recombiner to OPERABLE status.

B. Two hydrogen recombiners inoperable.

C. Required Action and associated Completion Time not met.

B.1 AND B.2 Verify by administrative means that the hydrogen control function is maintained.

Restore o hydrogen recomb, er to OPERABLE statu our AND Once per 1 thereafter 7 days 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months

/

C.1 X

ein MODE 3.

6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months

=

,/,

Farley Units 1 and 2 3.6.7-1 Amendment No. 146 (Unit 1)

Amendment No. 137 (Unit 2)

SURVEILLANCE R IREMENTS ydrogen Recombiners 3.6.7 SURVEILLANCE

/

FREQUENCY SR 3.6.7/

Perform a system functional te for each hydrogen 18 months recombiner.

/

3.6.7.2 Visually examine each drogen recombiner enclosure and verifyeere is no evidence of abnormal conditio s.

I1 o

/

SR 3.6.7.3 Perform a r stance to ground test for each heater 18 months phase.

/

Farley Units n

3.6.7-AAmendment No 14 nit 1) rmendment No.

(Unit 2)

A

TABLE OF CONTENTS 3.4 REACTOR COOLANT SYSTEM (RCS)................................................ 3.4.1-1 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits...............................................

3.4.1-1 3.4.2 RCS Minimum Temperature for Criticality...................................... 3.4.2-1 3.4.3 RCS Pressure and Temperature (P/T) Limits................................. 3.4.3-1 3.4.4 RCS Loops-MODES 1 and 2...............................................

3.4.4-1 3.4.5 RCS Loops-MODE 3..................

............................. 3.4.5-1 3.4.6 RCS Loops-MODE 4..................

............................. 3.4.6-1 3.4.7 RCS Loops-MODE 5, Loops Filled............................................. 3.4.7-1 3.4.8 RCS Loops-MODE 5, Loops Not Filled....................................... 3.4.8-1 3.4.9 Pressurizer................................................

3.4.9-1 3.4.10 Pressurizer Safety Valves......................

......................... 3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)...................... 3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP) System..........

3.4.12-1 3.4.13 RCS Operational LEAKAGE.....................................

........... 3.4.13-1 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage..................

.............. 3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation................................

....... 3.4.15-1 3.4.16 RCS Specific Activity................................................

3.4.16-1.

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)...............

............. 3.5.1-1 3.5.1 Accumulators................................................ 3.5.1-1 3.5.2 ECCS-Operating................................................ 3.5.2-1 3.5.3 ECCS-Shutdown................................................ 3.5.3-1 3.5.4 Refueling Water Storage Tank (RWST)......................................... 3.5.4-1 3.5.5 Seal Injection Flow...............................................

3.5.5-1 3.5.6 ECCS Recirculation Fluid pH Control System..................

.............. 3.5.6-1 3.6 CONTAINMENT SYSTEMS................................................

3.6.1-1 3.6.1 Containment................................................

3.6.1-1 3.6.2 Containment Air Locks...............................................

3.6.2-1 3.6.3 Containment Isolation Valves...............................................

3.6.3-1 3.6.4 Containment Pressure.................

.............................. 3.6.4-1 3.6.5 Containment Air Temperature...........................................

..... 3.6.5-1 3.6.6 Containment Spray and Cooling Systems...................................... 3.6.6-1 3.6.7 Deleted................................................

3.6.7-1......

l 3.6.8 Hydrogen Mixing System (HMS)................................................ 3.6.8-1 3.6.9 Reactor Cavity Hydrogen Dilution System...................................... 3.6.9-1 3.7 PLANT SYSTEMS................................................ 3.7.1-1 3.7.1 Main Steam Safety Valves (MSSVs).............................................. 3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs)............................................ 3.7.2-1 Farley Units 1 and 2 ii Amendment No.

(Unit 1)

Amendment No.

(Unit 2)

PAM Instrumentation 3.3.3 3.3 INSTRUMENTATION 3.3.3 Post Accident Monitoring (PAM) Instrumentation LCO 3.3.3 The PAM instrumentation for each Function in Table 3.3.3-1 shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS 1P4

1.

LCO 3.0.4 is not applicable.

c~

2.

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more Functions A.1 Restore required channel 30 days with one required to OPERABLE status.

channel inoperable.

B.

Required Action and B.1 Initiate action in Immediately associated Completion accordance with Time of Condition A Specification 5.6.8.

not met.

C.

One or more Functions C.1 Restore one channel to 7 days with two required OPERABLE status.

channels inoperable.

I Farley Units 1 and 2 3.3.3-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2)

PAM Instrumentation 3.3.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME D.

Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C Table 3.3.3-1 for the not met.

channel.

E.

As required by Required E.1 Be in MODE 3.

6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Action D.1 and referenced in AND Table 3.3.3-1.

E.2 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months F. As required by Required F.1 Initiate action in Immediately Action D.1 and accordance with referenced in Specification 5.6.8.

Table 3.3.3-1.

SURVEILLANCE REQUIREMENTS NOTE--------------------------------------------------------------

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

SURVEILLANCE FREQUENCY SR 3.3.3.1 Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized.

SR 3.3.3.2 Perform CHANNEL CALIBRATION.

18 months I

I I

Farley Units 1 and 2 3.3.3-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2)

PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 1 of 1)

Post Accident Monitoring Instrumentation CONDITION REFERENCED FROM REQUIRED REQUIRED FUNCTION CHANNELS ACTION D.1

1. RCS Hot Leg Temperature (Wide Range) 2 E

2. RCS Cold Leg Temperature (Wide Range) 2 E

3. RCS Pressure (Wide Range) 2 E

4. Steam Generator (SG) Water Level (Wide or 2/SG E

Narrow Range)

5. Refueling Water Storage Tank Level 2

E

6. Containment Pressure (Narrow Range) 2 E

7. Pressurizer Water Level 2

E

8. Steam Line Pressure 2/SG E

9. Auxiliary Feedwater Flow Rate 2

E

10. RCS Subcooling Margin Monitor 2

E

11. Containment Water Level (Wide Range) 2 E

12. Core Exit Temperature - Quadrant 1 2(a)

E

13. Core Exit Temperature - Quadrant 2 2(a)

E

14. Core Exit Temperature - Quadrant 3 2(a)

E

15. Core Exit Temperature - Quadrant 4 2(a)

E

16. Reactor Vessel Level Indicating System 2

F

17. Condensate Storage Tank Level 2

E

18. Deleted

19. Containment Area Radiation (High Range) 2 F

(a) A channel consists of two core exit thermocouples.

Farley Units 1 and 2 3.3.3-3 Amendment No.

Amendment No.

(Unit 1)

(Unit 2)

Hydrogen Recombiners 3.6.7 DELETED additional page deleted:

3.6.7-2 Farley Units 1 and 2 3.6.7-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2)

TABLE OF CONTENTS B 3.4.3 B 3.4.4 B 3.4.5 B 3.4.6 B 3.4.7 B 3.4.8 B 3.4.9 B 3.4.10 B 3.4.11 B 3.4.12 B 3.4.13 B 3.4.14 B 3.4.15 B 3.4.16 B 3.5 B 3.5.1 B 3.5.2 B 3.5.3 B 3.5.4 B 3.5.5 B 3.5.6 RCS Pressure and Temperature (PIT) Limits............................. B 3.4.3-1 RCS Loops-MODES 1 and 2........................................

B 3.4.4-1 RCS Loops-MODE 3........................................

B 3.4.5-1 RCS Loops -MODE 4........................................

B 3.4.6-1 RCS Loops-MODE 5, Loops Filled........................................ B 3.4.7-1 RCS Loops-MODE 5, Loops Not Filled................................... B 3.4.8-1 Pressurizer........................................

B 3.4.9-1 Pressurizer Safety Valves........................................

B 3.4.10-1 Pressurizer Power Operated Relief Valves (PORVs)........................................

B 3.4.11-1 Low Temperature Overpressure Protection (LTOP)

System........................................

B 3.4.12-1 RCS Operational LEAKAGE........................................

B 3.4.13-1 RCS Pressure Isolation Valve (PIV) Leakage............................. B 3.4.14-1 RCS Leakage Detection Instrumentation.................................... B 3.4.15-1 RCS Specific Activity........................................

B 3.4.16-1 EMERGENCY CORE COOLING SYSTEMS (ECCS)......................... B 3.5.1-1 Accumulators........................................

B 3.5.1-1 ECCS -

Operating........................................ B 3.5.2-1 ECCS-Shutdown........................................ B 3.5.3-1 Refueling Water Storage Tank (RWST)..................................... B 3.5.4-1 Seal Injection Flow........................................

B 3.5.5-1 ECCS Recirculation Fluid pH Control System............................. B 3.5.6-1 B 3.6 CONTAINMENT SYSTEMS........................................

B 3.6.1-1 B 3.6.1 Containment........................................

B 3.6.1-1 B 3.6.2 Containment Air Locks........................................

B 3.6.2-1 B 3.6.3 Containment Isolation Valves........................................

B 3.6.3-1 B 3.6.4 Containment Pressure........................................

B 3.6.4-1 B 3.6.5 Containment Air Temperature........................................

B 3.6.5-1 B 3.6.6 Containment Spray and Cooling Systems................................... B 3.6.6-1 B 3.6.7 qen Rec biners./

........................../

.: B 3.6.7-1 B 3.6.8 Hydrogen Mixing System (HMS).B 3.6.8-1 B 3.6.9 Reactor Cavity Hydrogen Dilution DELETED System (RCHDS)....

B 3.6.9-1 B 3.7 PLANT SYSTEMS.............................

B 3.7.1-1 B 3.7.1 Main Steam Safety Valves (MSSVs)..........

................... B 3.7.1-1 B 3.7.2 Main Steam Isolation Valves (MSIVs).............................

B 3.7.2-1 B 3.7.3 Main Feedwater Stop Valves and Main Feedwater Regulation Valves (MFRVs) and Associated Bypass Valves........................

B 3.7.3-1 B 3.7.4 Atmospheric Relief Valves (ARVs)........................

B 3.7.4-1 Farley Units 1 and 2 ii Revision 0

PAM Instrumentation B 3.3.3 BASES APPLICABLE PAM instrumentation that meets the definition of Type A in Regulatory SAFETY ANALYSES Guide 1.97 satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). The (continued) specified Category I, non-Type A, instrumentation must be retained in TS because it is intended to assist operators in minimizing the consequences of accidents. Therefore, these Category I, non-Type A, variables are important for reducing public risk.

LCO The PAM instrumentation LCO provides OPERABILITY requirements for Regulatory Guide 1.97 Type A monitors, which provide information required by the control room operators to perform certain manual actions specified in the unit Emergency Operating Procedures.

These manual actions ensure that a system can accomplish its safety function, and are credited in the safety analyses. Additionally, this LCO addresses certain Regulatory Guide 1.97 instruments that have been designated Category I, non-Type Al and one ins ent (HdenMonitorpfat is neithe3eabtegory I nor ie A that ha

,enicuethnis LCO dusgd-ts post acn function./

The OPERABILITY of the PAM instrumentation ensures there is sufficient information available on selected unit parameters to monitor and assess unit status following an accident. This capability is consistent with the recommendations of Reference 1.

LCO 3.3.3 requires two OPERABLE channels for most Functions.

Two OPERABLE channels ensure no single failure prevents operators from getting the information necessary for them to determine the safety status of the unit, and to bring the unit to and maintain it in a safe condition following an accident.

Furthermore, OPERABILITY of two channels allows a CHANNEL CHECK during the post accident phase to confirm the validity of displayed information.

Table 3.3.3-1 lists all Type A and certain Category I variables identified by the unit specific Regulatory Guide 1.97 analyses, as amended by the NRC's SER.

(continued)

Farley Units 1 and 2 B 3.3.3-3 Revision 0

PAM Instrumentation B 3.3.3 BASES LCO

17.

Condensate Storage Tank (CST) Level (continued)

CST Level is provided to ensure water supply for auxiliary feedwater (AFW). The CST provides the ensured safety grade water supply for the AFW System. The CST consists of a tank and outlet header. Inventory is monitored by two.5 - 11 feet of water indications for the tank. CST Level is displayed on control room indicators, and plant computer. In addition, control room annunciators alarm on low and low-low level.

CST Level is considered a Category I, Type A variable because the control room meter and annunciator are considered the primary indication used by the operator.

The DBAs that require AFW are the loss of offsite power, steam line break (SLB), and small break LOCA.

The CST is the initial source of water for the AFW System.

However, as the CST is depleted, manual operator action is necessary to replenish the CST or align suction to the AFW pumps from the Service Water System.

18.

Hydrogen Monitors

/

Hydrogen Monito are provided to detect gh hydrogen concentration nditions that represent potential for containmen reach from a hydrogen xplosion. This varia e is also impo ant in verifying the ade acy of mitigating ack ns.

DELETD The Hydrogen Monitors are not ype A or Category l instr mentation (Ref. 1). Th are included in this 0 due to t

ir post accident functio nd to maintain consj tency with.the ocation of this instrume ation in the Standar estinghouse Technical Specificats.

19.

Containment Area Radiation (High Rangel Containment Area Radiation is a Category I variable provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans. Containment radiation level is used to determine if a high energy line break (HELB) has occurred, and whether the event is inside or outside of containment.

Farley Units 1 and 2 B3 3.3.3-1 1 Revision 0

PAM Instrumentation B 3.3.3 BASES ACTIONS B. 1 (continued)

Condition B applies when the Required Action and associated Completion Time for Condition A are not met. This Required Action specifies initiation of actions in Specification 5.6.8, which requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability, if performed, and identifies proposed restorative actions. This action is appropriate in lieu of a shutdown requirement since alternative actions are identified before loss of functional capability, and given the likelihood of unit conditions that would require information provided by this instrumentation.

C.1 Condition C applies when one or more Functions have two inoperable required channels (i.e., two channels inoperable in the same Function). Required Action C.1 requires restoring one channel in the Function(s) to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrument operation and the availability of alternate means to obtain the required information. Continuous operation with two required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation.

Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur.

Con on C is modified by a te that excludes hyd gen monitor ch Inels.

Condition D app~ s when two hydroge monitor channels are inoperable.

quired Action D.1 re res restoring one hy gen monitor ch Inel to OPERABLE S tus within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

e 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Comple n Time is reasonabl ased on other core d age

asses, ent capabilities av able to provide inform ion for operator de ions. Also, it is unli y that a LOCA (whic ould cause core mage) would occur ring this time.

(continued)

Farley Units 1 and 2 B 3.3.3-13 Revision 16

ACTIONS (continue PAM Instrumentation B 3.3.3 led)lL Conditi n applies when the Required Action and associated Compi ion Time of Condition Cw are not met. Required Actior.1 requires entering the appropriate Condition referenced in Table 3.3.3-1 for the channel immediately. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met any Required Action of Condition C g'~and the associated Completion Time has expired, Condition is E_

entered for that channel and provides for transfer to the appropriatH subsequent Condition.

an 2

If the Required Action and associated Completion Time of ConditiorjC~are not met and Table 3.3.3-1 directs entry into Condii the unit must be brought to a MODE where the 3q-rements of this LCO do not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power F

conditions in an orderly manner and without challenging unit systems.

Alternate means of monitoring Reactor Vessel Water Level and Containment Area Radiation have been developed. These alternate means may be utilized if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. If these alternate means are used, the Required Action is not to shut down the unit but rather to follow the directions of Specification 5.6.8, in the Administrative Controls section required to mitigate of the TS. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels. The alternate means of monitoring the affected PAM Channel should be identified or installed, if necessary, prior to submitting the report to the NRC. An acceptable alternate means of monitoring Reactor Vessel Water Level is to monitor pressurizer level and upperhead subcooling.

Farley Units 1 and 2 B 3.3.3-14 Revision 0

PAM Instrumentation B 3.3.3 BASES SURVEILLANCE REQUIREMENTS SR 3.3.3.2 (continued)

The hydrogen m itors are calibrated u sample gases contain'

a.

Tenvume percent hydroge balance nitrogen, for ze check.

b.

n volume percent hy gen, balance nitrogen, xed with

/compressed air, for s n check.

The Frequency is based on operating experience and consistency with the typical industry refueling cycle.

REFERENCES

1.

A-181866 Unit 1 RG 1.97 Compliance Review A-204866 Unit 2 RG 1.97 Compliance Review NRC SER for FNP RG 1.97 Compliance Report, Letter, Reeves to McDonald, 2/12/87.

2.

Regulatory Guide 1.97.

3.

NUREG-0737, Supplement 1, "TMI Action Items."

Farley Units 1 and 2 B 3.3.3-16 Revision 0

PAM Instrumentation B 3.3.3 Table B 3.3.3-1 (page 1 of 1)

Post Accident Monitoring Instrumentation NTRUMENTATION

{PRIVATE )PAM INS TPNS RCS Hot Leg Temperature (Wide Range)

RCS Cold Leg Temperature (Wide Range)

RCS Pressure (Wide Range)

Steam Generator (SG) Water Level Refueling Water Storage Tank Level Containment Pressure (Narrow Range)

Pressurizer Water Level Steam Line Pressure Auxiliary Feewater Flow Rate RCS Subcooling Margin Monitor Containment Water Level (Wide Range)

Core Exit Temperature Reactor Vessel Level Indicating System Condensate Storage Tank Level Hydropr1ionitors Containment Area Radiation (High Range)

TE-413, TE-423, TE-433 TE-410, TE-420, TE-430 PT-402, PT-403 Wide Range - LT-477, LT-487, LT-497 Narrow Range - LT-474, LT-475, LT-476 LT-484, LT-485, LT-486 LT-494, LT-495, LT-496 LT-501, LT-502 PT-950, PT-951, PT-952, PT-953 LT-459, LT-460, LT-461 PT-474, PT-475, PT-476 PT-484, PT-485, PT-486 PT-494, PT-495, PT-496 FT-3229A, FT-3229B, FT-3229C Q1 (2) H11 NGCCM2523A&B LT-3594A, LT-3594B TE-2301 - TE-2351 LE-2352, LE-2353 LT-515, LT-516 AIT-OA 2 AIT-2703B RE-27A, RE-27B Farley Units 1 and 2 B 3.3.3-17 Revision 0

IDELEE7D Hydrogen Recombiners B 3.6.7 B 3.6 CONTAINMEN YSTEMS B 3.6.7 Hydrog Recombiners BASES B

KGROUND T

unction of the hydrogen reco ners is to eliminate the ential reach of containment due to a drogen oxygen reaction.

Per 10 CFR 50.44, "Stand dfor Combustible Gas ntrol Systems in Light-Water-Cooled R actors" (Ref. 1), and GD 41, "Containment Atmosphere Cleanup" ef. 2), hydrogen recoinners are required to reduce the hydrog concentration in the con iinment following a loss of coolant accid t (LOCA) or steam line b ak (SLB). The recombiners complish this by recombi ng hydrogen and oxygen to form water apor. The vapor remains, containment, thus eliminating any disc rge to the environment.

e hydrogen recombiners are manu y initiated since flamma limits would not be reached until se ral days after a Design B is Accident (DBA).

Two 100% capacity inde endent hydrogen recombiner syste are provided. Each consi s of controls located in the control r m, a power supply and ecombiner. Recombination is acco plished by heating a hydro n air mixture above 1 1 507F. The re Iting water vapor and dis iarge gases are cooled prior to disc rge from the recombinerjA single recombiner is capable of intaining the hydroge pconcentration in containment below e 4.0 volume percent

/(vl) fminmability limit. Two recombiners a; provided to meet the re irement for redundancy and indepe ence. Each recombiner is wered from a separate Engineered afety Features bus, and is

////provided with a separate power pOa and control panel.

APPLICABLE SAFETY AN YSE The hydrogen recombiners vide for the capability of controllin the S

bulk hydrogen concentr on in containment to less than the loIer flammable concentra~ n of 4.0 v/o following a DBA. This c trol would prevent a co ainment wide hydrogen burn, thus e suring the pressure and te perature assumed in the analyses ar not exceeded. T limiting DBA relative to hydrogen g eration is a LOCA. Hy ogen may accumulate in containme following a LOCA as a res of:

(continued)

I z

/

Farley Units 1 and 2 B 3.6.7-1 Revision 0

Hydrogen Rec iners B 3.6.7 BASE PLICABLE a A metal steam re on between the zirco um fuel rod cladding SAFETY ANALYSES and the reacto oolant; (continued)

b. Radiolytic ecomposition of water* the Reactor Coolant stem (RCS) d the containment sul

c. H rogen in the RCS at t time of the LOCA (i.e ydrogen issolved in the reactor oolant and hydrogen s in the pressurizer vapor s e); or

d. Corrosion of m ls exposed to contai ent spray and Emergency re Cooling System so ions.

To evaluat he potential for hydro n accumulation in cont ment followin LOCA, the hydrogen eneration as a function time follow' g the initiation of the cident is calculated. Co ervative as mptions recommende y Reference 3 are use o maximize the ount of hydrogen cal ated.

Based on the cons ative assumptions use o calculate the hydrogen conce ration versus time after LOCA, the hydrogen concentrations the primary containme would reach 3.5 v/o abo 13 days af the LOCA and 4.0 v/o out 5 days later if no recombi r was functioning -(Ref.. Initiating the hydrogen, reco iners when the primary ontainment hydrogen con ntration re es 3.5 v/o will maintai e hydrogen concentratio in the imary containment bel flammability limits.

The hydrogen reco ners are designed such t at, with the conservatively ca lated hydrogen generati rates discussed above, a single combiner is capable of Iiiting the peak hydrogen concentratio in containment to less th 4.0 v/o (Ref. 4). The Post Accident drogen Purge System is esigned such that it is an adequ e backup to the redundan ydrogen recombiners.

T hydrogen recombiners s isfy Criterion 3 of 10 CFR 0.36(c)(2)(ii).

LCO Two hydrogen rec mbiners must be OPERABL.

This ensures

/operation of atast one hydrogen recombin the event of a worst case single tive failure.

/tinued)

Farley Units 1 and 2

/

B 3.6.7-2 Revision 0

R A F S Hydrogen Reco iners 3.6.7 LC eration with at least e hydrogen recombin ensures that the (continued) post LOCA hydroge oncentration can be p vented from exceedin the flammability

/i APPLICA BI In MODE and 2, two hydrogen embiners are requir o control

/

the hyd gen concentration wit containment below it lammability limit 4.0 v/o following a LO A, assuming a worst se single failure.

MODES 3 and 4, bothe hydrogen producti rate and the total hydrogen produced er a LOCA would be Is than that calculated for the DBA LOC Also, because of the ited time in these MODES, the pr ability of an accident quiring the hydrogen/

recombiners' low. Therefore, the lydrogen recombiners are ot required i ODE 3 or 4.

In M ES 5 and 6, the prob ility and consequences a LOCA are log

,due to the pressure d temperature limitation in these MODES.

herefore, hydrogen re mbiners are not reqr in these MODES.

ACT IONS A.1 With one ntainment hydrogen re mbiner inoperable, the inoper e recombiner must be stored to OPERABLE sta s within 30 das. In this condition, th emaining OPERABLE hy ogen r

ombiner is adequate to rform the hydrogen contr function.

owever, the overall reliility is reduced because ingle failure in the OPERABLE reco iner could result in reduc hydrogen control capability. The 30 ay Completion Time is ba d on the availability of the other hydrogn recombiner, the small p ability of a LOCA or SLB occurrin that would generate an a ount of hydrogen that exceeds th flammability limit), and th amount of time available aft a LOCA r SLB (should one occur) r operator action to prevent hydren accumulation from exc ding the flammability limit.

equired Action A.1 has be modified by a Note that stas the provisions of LCO 3.0.4 e not applicable. As a result MODE change is allowed wh ne recombiner is inoperab

. This (cont ued)

/

Farley Units 1 and 2 B

B 3.6.7-3 vision 0

GARY/

Hydrogen Rec biners

/B 3.6.7 I

TIONS A1 (continued) allowance is ba d on the availability of e other hydrogen recombiner, t small probability of a OCA or SLB occurrin hat would gen ate an amount of hydr aen that exceeds the fi nmability limit), a the amount of time av ilable after a LOCA or B (should one cur) for operator actio o prevent hydrogen a umulation from ex eding the flammability mit.

/.1 and B.2 With two hydroa recombiners inoper e, the ability to perform e

hydrogen co ol function via alternat capabilities must be ver ed by administra' e means within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months The alternate hydroge ontrol capabili s are provided by the ntainment Post Accide Hydrogen Purg ystem. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months C pletion Time allows a asonable pe i d of time to verify tha loss of hydrogen contr function does t exist. Both the initial erification and all subse ent verifications may be performed as n administrative check examining logs or other information t determine the availabilitof the alternate/

hydrogen contr system. It does not me 6 to perform the Surveillances, eeded to demonstrate ERABILITY of the altern e hydrogen ntrol system. If the abil to perform the hydrogen control f ction is maintained co inued operationis~perrmitt with two h rogen recombiners inorable for up to 7 days. S en days is a r sonable time to allow t hydrogen recombiners t e

operable because the h rogen control function is aintained and because of the low pro ability of the occurrence o LOCA that would generate hydrogen the amounts capable of e ceeding the flammability limit.

C.1 01 If the iprable hydrogen recoi er(s) cannot be restored to OP BLE status within the r uired Completion Time, the ant st be brought to a MODE*

which the LCO does not ap y. To chieve this status, the pl t must be brought to at leaspODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Co pletion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is ree onable, based on operating experie e, to reach MODE 3 from f power conditions in an orderly man r and without challenging pI t systems.

Farley Units 1 and 2/B B 3.6.7-4 //

//

Revision 0

Hydrogen Reco iners B 3.6.7 BASE S

VEILLANCE R 3.6.7.1 EQUIREMENTS Performance of ystem functional test r each hydrogen recombiner e res the recombiners e operational and cantain and sustain e temperature neces ry for hydrogen recomn ation.

In partic r, this SR verifies that e minimum heater sh th tempe ture increases to 2 70 F in s 90 minutes. A reaching

700, the power is increas to maximum power f approximately Mutes and power is vdified to be 2 60 kW.

Operating experien has shown that these mponents usually pas the Surveillance en performed at the month Frequency.

Therefore, the requency was conclu d to be acceptable from reliability st dpoint.

SR 3...2 s R ensures there ar physical problems t t could affect recombiner operation.

ince the recombiners mechanically passive, they are n subject to mechanical fure. The only credible failure involves lo of power, blockage of e internal flow, missile impact, etc.

A visual i pection is sufficient to termine abnormal conditi s that could use such failures (i.e., Iose wiring or structural co

ections, dep its of foreign materials tc.). The 18 month Freq ncy for this was developed consid ing the incidence of hydrogen recombiners failing the in the past is low.

SR 3.6.7.3 This SR req es performance of a resis nce to ground test for each heater ph e to ensure that there arefo detectable grounds in any heater ase. This is accomplishe y verifying that the resista e to grou for any heater phase is 0,000 ohms following the

/p jormance of the required f ctional test.

The 18 month Frequenc or this Surveillance was de oped

/ considering the incidece of hydrogen recombinersoiling the SR in the past is low.Co ent located at end of above ne.

Farley Units 1 and 2 B 3.6.7-5

/

/Revision 0

Hydrogen Re iners B3.6.7

BASE, ERENCES 10 CFR 50.44.

2. 10 CFR 50, pendix A, GDC 41.

2 B 3.6.7-6

HMS B 3.6.8 B 3.6 CONTAINMENT SYSTEMS B 3.6.8 Hydrogen Mixing System (HMS)

BASES The HMS reduces the potential for breach of containment due to a hydrogen oxygen reaction by providing a uniformly mixed post accident containment atmosphere, thereby minimizing the potential for local hydrogen burns due to a pocket of hydrogen above the flammable concentration Maintaining4, uniformly mixe r

consihnent atmosphere nt eHsuis that the hn d Sgen monitors (i

Ie and accurateoe asuTe of the buk ha oien concentration ac ive the operat the capability of prev ting the occurrence gabulk, hodtwen burn inside cown m ntopers a

CFRo50l.E

, Standards for 1,00cmbustible Gas Contrainsae in Light-Wautocaoled Reactorsa pref. 1), and 1S0 CFR a gle fan Contannroid Atmosphere Cleanup" (Ref. 2);/

The post accident HMS is an Engineered Safety Feature (ESF) and is designed to withstand a loss of coolant accident (LOCA) without loss of function. The System has two independent trains, each consisting of two fans with their own motors and controls. Each train is sized for 15,000 cfm. The two trains are initiated automatically on a Safety Injection signal. Each train is powered from a separate emergency power supply. Since a single fan can provide 100% of the mixing requirements, the System will provide its design function with a limiting single active failure.

Air is drawn from the steam generator compartments by the locally mounted mixing fans and is discharged toward the upper regions of the containment. This complements the air patterns established by the containment air coolers, which take suction above the operating floor level and discharge to the lower regions of the containment, and the containment spray, which cools the air and causes it to drop to lower elevations. The systems work together such that potentially stagnant areas where hydrogen pockets could develop are eliminated.

When performing their post accident hydrogen mixing function, the hydrogen mixing fans are designed to prevent motor overload in a post accident high pressure environment. The design flow rate is based on the minimum air distribution requirements to eliminate stagnant hydrogen pockets. Each train is redundant (in excess of full required capacity) and is powered from an independent ESF bus.

Farley Units 1 and 2 B 3.6.8-1 Revision 0

HMS B 3.6.8 BASES LCO by a Safety Injection signal. Only one fan per train is required (continued)

OPERABLE for the train to be considered OPERABLE.

Operation with at least one HMS fan provides the mixing necessary to ensure uniform hydrogen concentration throughout containment.

APPLICABILITY In MODES I and 2, the two HMS trains ensure the capability to prevent localized hydrogen concentrations above the flammability limit of 4.0 volume percent in containment assuming a worst case single active failure.

In MODE 3 or 4, both the hydrogen production rate and the total hydrogen produced after a LOCA would be less than that calculated for the DBA LOCA. Also, because of the limited time in these MODES, the probability of an accident requiring the HMS is low.

Therefore, the HMS is not required in MODE 3 or 4.

In MODES 5 and 6, the probability and consequences of a LOCA or steam line break (SLB) are reduced due to the pressure and temperature limitations in these MODES. Therefore, the HMS is not required in these MODES.

ACTIONS A.1 With one HMS train inoperable, the inoperable train must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE HMS train is adequate to perform the hydrogen mixing function. However, the overall reliability is reduced because a single failure in the OPERABLE train could result in reduced hydrogen mixing capability, although the capacity of a single fan is sufficient to provide adequate mixing. The 30 day Completion Time is based on the availability of the other HMS train, the small probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability limit), the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit, and the availability of tho hydr genw coq2bLers, Containment Spray System Post Accident Hydrogen Purge Systeml app hyogeMon r l and the (continued)

Farley Units 1 and 2 8 3.6.8-3 Revision 0

HMS B 3.6.8 BASES ACTIONS A.1 (continued)

Required Action A.1 has been modified by a Note that states the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when one HMS train is inoperable. This allowance is based on the availability of the other HMS train, the small probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability limit), and the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit.

B.1 and 8.2 lility is With two HMS trains inoperable, the ability to perform the hydrogen control function via alternate capabilities must be verified by administrative means within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The alternate hydrogen control I ca ba ie ar rovided by the containment Post Accident Hydrogen Purge System or drogrrec imnerl The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time allows a reasonable penooo time-to verify that a loss of hydrogen control function does not exist. Both the initial verification and all subsequent verifications may be performed as an administrative check, by examining logs or other information to determine the availability of the alternate hydrogen control system. It does not mean to-perform the Surveillances needed t-de-nioristrate OPERABILITY of the alternate hydrogen control system. If the ability to perform the hydrogen control function is maintained, continued operation is permitted with two HMS trains inoperable for up to 7 days. Seven days is a reasonable time to allow two HMS trains to be inoperable because the hydrogen control function is maintained and because of the low probability of the occurrence of a LOCA that would generate hydrogen in the amounts capable of exceeding the flammability limit.

C.1 If an inoperable HMS train cannot be restored to OPERABLE status within the required Completion Time, 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 at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-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.

Farley Units 1 and 2

-B 3.6.8-4 Revision 0

HMS B 3.6.8 BASES SURVEILLANCE SR 3.6.8.1

'REQUIREMENTS Operating each HMS train for 2 15 minutes ensures that each train is OPERABLE and that all associated controls (including starting from the control room) are functioning properly.. It also ensures that blockage, fan and/or motor failure, or excessive vibration can be detected for corrective action. While this system is not included in the scope of the Inservice Testing (IST) Program, the 92 day Frequency is consistent with IST Program Surveillance Frequencies, operating experience, the known reliability of the fan motors and controls, and the two train redundancy available.

SR 3.6.8.2 Verifying that each HMS fan speed is 21 320 rpm ensures that each train is capable of maintaining localized hydrogen concentrations below the flammability limit. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.6.8.3 This SR ensures that each HMS train responds properly to a Safety Injection actuation signal. The Surveillance verifies that each fan starts from the nonoperating condition. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.Comment located at end of above line.

REFERENCES

1. I P/CFR

.44/-

2. 1 1(FR 5O Appens A, GD41

3. Regulatory Guide 1.7, Revision 1.

4. WCAP 7901, Revision 1.

Farley Units 1 and 2 B 3.6.8-5 Revision 4

Reactor Cavity Hydrogen Dilution System B 3.6.9 B 3.6 CONTAINMENT SYSTEMS B 3.6.9 Reactor Cavity Hydrogen Dilution System (RCHDS)

BASES BACKGROUND The RCHDS reduces the potential for breach of containment due to a hydrogen oxygen reaction by providing a uniformly mixed post accident containment atmosphere, thereby minimizing the potential for local hydrogen burns due to a pocket of hydrogen above the flammable also ensures thKh yrgnmoitor 1il give an accua me asure of the bulk In rgen concentration~i give the opera~tor~. 'e capability

ofpeet, the occurrence o rtulk hydrogen burn Uiide cnanetper 10 CFR 50./tndards for Conn stible Gas Contrp Systes in Light-Water-Co ed Reactors" (Ref. 1, and 10 CFR 50, G

41 Containment os here Cleanup" Mef. 2).

The post accident RCHDS is an Engineered Safety Feature (ESF) and is designed to withstand a loss of coolant accident (LOCA) without loss of function. The System has two independent trains, each consisting of one fan with its own motor and controls. Each train is sized for 270 cfm (Unit 1) and 1570 cfm (Unit 2).

The two trains are initiated automatically on a Safety Injection signal.

Each train is powered from a separate emergency power supply.

Since each train fan can provide 100% of the mixing requirements, the System will provide its design function with a limiting single active failure. The RCHDS ventilates the reactor cavity to ensure that this volume is available for the dilution of containment hydrogen, and to maintain hydrogen concentrations in this volume in equilibrium with that of the remainder of the containment. The RCHDS fans discharge into the reactor cavity through a circular header embedded in the cavity wall at an elevation approximately coincident with that of the lower reactor vessel head. The RCHDS discharge flows from the cavity upward around the reactor vessel and outward through the incore instrument chase. The RCHDS fans take suction from the periphery of the containment just below the operating floor. The design flow rate is based on the minimum air distribution requirements to eliminate stagnant hydrogen pockets. The RCHDS and Hydrogen Mixing System work together such that potentially stagnant areas where hydrogen pockets could develop are eliminated.

Farley Units 1 and 2 B 3.6.9-1 Revision 0

Reactor Cavity Hydrogen Dilution System B 3.6.9 BASES APPLICABILITY In MODE 3 or 4, both the hydrogen production rate and the total (continued) hydrogen produced after a LOCA would be less than that calculated for the DBA LOCA. Also, because of the limited time in these MODES, the probability of an accident requiring the RCHDS is low.

Therefore, the RCHDS is not required in MODE 3 or 4.

In MODE 5 or 6, the probability and consequences of a LOCA or steam line break (SLB) are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RCHDS is not required in these MODES.

ACTIONS A.1 With one RCHDS train inoperable, the inoperabale train must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE RCHDS train is adequate to perform the hydrogen mixing function. However, the overall reliability is reduced because a single failure in the OPERABLE train could result in reduced hydrogen mixing capability. The 30 day Completion Time is based on the availability of the other RCHDS train, the small probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability limit), the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit, and the availability of tho h~

gen co'

ers, Containment Spray System Post Accident Venting Syster"5d h ro 0

5 and the Required Action A.1 has been modified by a Note that states the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when one RCHDS train is inoperable. This allowance is based on the availability of the other RCHDS train, the small probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability'limit), and the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit.

B.1 If an inoperable RCHDS train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a (continued)

Farley Units 1 and 2 B 3.6.9-3 Revision 0

Reactor Cavity Hydrogen Dilution System B 3.6.9 BASES ACTIONS B.1 (continued)

MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-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.

SURVEILLANCE SR 3.6.9.1 REQUIREMENTS Operating each RCHDS train for > 15 minutes ensures that each train is OPERABLE and that all associated controls are functioning.

properly and that each fan may be started by operator action from the control room. It also ensures that blockage, fan and/or motor failure, or excessive vibration can be detected for corrective action. While this system is not included in the scope of the Inservice Testing (IST)

Program, the 92 day Frequency is consistent with IST Program Surveillance Frequencies, operating experience, the known reliability of the fan motors and controls, and the two train redundancy available.

SR 3.6.9.2 This SR ensures that each RCHDS train responds properly to a Safety Injection signal. The Surveillance verifies that each fan starts from the non-operating condition. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES

1. !

E9iFRg644 LETED

2.

110 CF50, Ap dix A, 41.

3. Regulatory Guide 1.7, Revision 0.

Farley Units 1 and 2 B 3.6.9-4 Revision 4

TABLE OF CONTENTS B 3.4.3 RCS Pressure and Temperature (P/T) Limits............................. B 3.4.3-1 B 3.4.4 RCS Loops-MODES 1 and 2......................................

B 3.4.4-1 B 3.4.5 RCS Loops-MODE 3......................................

B 3.4.5-1 B 3.4.6 RCS Loops-MODE 4......................................

B 3.4.6-1 B 3.4.7 RCS Loops-MODE 5, Loops Filled......................................

B 3.4.7-1 B 3.4.8 RCS Loops-MODE 5, Loops Not Filled................................... B 3.4.8-1 B 3.4.9 Pressurizer......................................

B 3.4.9-1 B 3.4.10 Pressurizer Safety Valves......................................

B 3.4.10-1 B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs).....

B 3.4.11-1 B 3.4.12 Low Temperature Overpressure Protection (LTOP)

System......................................

B 3.4.12-1 B 3.4.13 RCS Operational LEAKAGE......................................

B 3.4.13-1 B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage............................. B 3.4.14-1 B 3.4.15 RCS Leakage Detection Instrumentation.................................... B 3.4.15-1 B 3.4.16 RCS Specific Activity...................................... B 3.4.16-1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)......................... B 3.5.1-1 B 3.5.1 Accumulators......................................

B 3.5.1-1 B 3.5.2 ECCS -

Operating......................................

B 3.5.2-1 B 3.5.3 ECCS-Shutdown......................................

B 3.5.3-1 B 3.5.4 Refueling Water Storage Tank (RWST)..................................... B 3.5.4-1 B 3.5.5 Seal Injection Flow......................................

B 3.5.5-1 B 3.5.6 ECCS Recirculation Fluid pH Control System B 3.5.6-1 B 3.6 CONTAINMENT SYSTEMS...................................... B 3.6.1-1 B 3.6.1 Containment......................................

B 3.6.1-1 B 3.6.2 Containment Air Locks......................................

B 3.6.2-1 B 3.6.3 Containment Isolation Valves.................

..................... B 3.6.3-1 B 3.6.4 Containment Pressure...................................... B 3.6.4-1 B 3.6.5 Containment Air Temperature................................

..... B 3.6.5-1 B 3.6.6 Containment Spray and Cooling Systems................................... B 3.6.6-1 B 3.6.7 Deleted......................................

B 3.6.7-1 B 3.6.8 Hydrogen Mixing System (HMS)..............................

B 3.6.8-1 B 3.6.9 Reactor Cavity Hydrogen Dilution System (RCHDS)..............................

B 3.6.9-1 B 3.7 PLANT SYSTEMS..............................

B 3.7.1-1 B 3.7.1 Main Steam Safety Valves (MSSVs)..............................

B 3.7.1-1 B 3.7.2 Main Steam Isolation Valves (MSIVs)..................

............ B 3.7.2-1 B 3.7.3 Main Feedwater Stop Valves and Main Feedwater Regulation Valves (MFRVs) and Associated Bypass Valves........

................ B 3.7.3-1 B 3.7.4 Atmospheric Relief Valves (ARVs)........................

B 3.7.4-1 Farley Units 1 and 2

PAM Instrumentation B 3.3.3 BASES APPLICABLE SAFETY ANALYSES (continued)

PAM instrumentation that meets the definition of Type A in Regulatory Guide 1.97 satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). The specified Category I, non-Type A, instrumentation must be retained in TS because it is intended to assist operators in minimizing the consequences of accidents. Therefore, these Category I, non-Type A, variables are important for reducing public risk.

LCO The PAM instrumentation LCO provides OPERABILITY requirements for Regulatory Guide 1.97 Type A monitors, which provide information required by the control room operators to perform certain manual actions specified in the unit Emergency Operating Procedures. These manual actions ensure that a system can accomplish its safety function, and are credited in the safety analyses. Additionally, this LCO addresses certain Regulatory Guide 1.97 instruments that have been designated Category I, non-Type A.

The OPERABILITY of the PAM instrumentation ensures there is sufficient information available on selected unit parameters to monitor and assess unit status following an accident. This capability is consistent with the recommendations of Reference 1.

LCO 3.3.3 requires two OPERABLE channels for most Functions.

Two OPERABLE channels ensure no single failure prevents operators from getting the information necessary for them to determine the safety status of the unit, and to bring the unit to and maintain it in a safe condition following an accident.

Furthermore, OPERABILITY of two channels allows a CHANNEL CHECK during the post accident phase to confirm the validity of displayed information.

Table 3.3.3-1 lists all Type A and certain Category I variables identified by the unit specific Regulatory Guide 1.97 analyses, as amended by the NRC's SER.

(continued)

Farley.Units 1 and 2 B 3.3.3-3

PAM Instrumentation B 3.3.3 BASES LCO

17.

Condensate Storage Tank (CST) Level (continued)

CST Level is provided to ensure water supply for auxiliary feedwater (AFW). The CST provides the ensured safety grade water supply for the AFW System. The CST consists of a tank and outlet header. Inventory is monitored by two.5 - 11 feet of water indications for the tank. CST Level is displayed on control room indicators, and plant computer. In addition, control room annunciators alarm on low and low-low level.

CST Level is considered a Category I, Type A variable because the control room meter and annunciator are considered the primary indication used by the operator.

The DBAs that require AFW are the loss of offsite power, steam line break (SLB), and small break LOCA.

The CST is the initial source of water for the AFW System.

However, as the CST is depleted, manual operator action is necessary to replenish the CST or align suction to the AFW pumps from the Service Water System.

18.

Deleted.

19.

Containment Area Radiation (High Range)

Containment Area Radiation is a Category I variable provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans. Containment radiation level is used to determine if a high energy line break (HELB) has occurred, and whether the event is inside or outside of containment.

(continued)

Farley Units 1 and 2 B 3.3.3-1 1

PAM Instrumentation B 3.3.3 BASES ACTIONS B.1 (continued)

Condition B applies when the Required Action and associated Completion Time for Condition A are not met. This Required Action specifies initiation of actions in Specification 5.6.8, which requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability, if performed, and identifies proposed restorative actions. This action is appropriate in lieu of a shutdown requirement since alternative actions are identified before loss of functional capability, and given the likelihood of unit conditions that would require information provided by this instrumentation.

C.1 Condition C applies when one or more Functions have two inoperable required channels (i.e., two channels inoperable in the same Function). Required Action C.1 requires restoring one channel in the Function(s) to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrument operation and the availability of alternate means to obtain the required information. Continuous operation with two required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation.

Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur.

(continued)

Farley Units 1 and 2 B 3.3.3-1 3

PAM Instrumentation B 3.3.3 BASES ACTIONS D.1 (continued)

Condition D applies when the Required Action and associated Completion Time of Condition C are not met. Required Action D.1 requires entering the appropriate Condition referenced in Table 3.3.3-1 for the channel immediately. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met any Required Action of Condition C and the associated Completion Time has expired, Condition D is entered for that channel and provides for transfer to the appropriate subsequent Condition.

E.1 and E.2 If the Required Action and associated Completion Time of Condition C are not met and Table 3.3.3-1 directs entry into Condition E, the unit must be brought to a MODE where the requirements of this LCO do not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

F.1 Alternate means of monitoring Reactor Vessel Water Level and Containment Area Radiation have been developed. These alternate means may be utilized if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. If these alternate means are used, the Required Action is not to shut down the unit but rather to follow the directions of Specification 5.6.8, in the Administrative Controls section required to mitigate of the TS. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels. The alternate means of monitoring the affected PAM Channel should be identified or installed, if necessary, prior to submitting the report to the NRC. An acceptable alternate means of monitoring Reactor Vessel Water Level is to monitor pressurizer level and upperhead subcooling.

(continued)

Farley Units 1 and 2 B 3.3.3-1 4

PAM Instrumentation B 3.3.3 BASES SURVEILLANCE SR 3.3.3.2 (continued)

REQUIREMENTS The Frequency is based on operating experience and consistency with the typical industry refueling cycle.

REFERENCES

1.

A-181866 Unit 1 RG 1.97 Compliance Review A-204866 Unit 2 RG 1.97 Compliance Review NRC SER for FNP RG 1.97 Compliance Report, Letter, Reeves to McDonald, 2112/87.

2.

Regulatory Guide 1.97.

3.

NUREG-0737, Supplement 1, MTMI Action Items.'

I Farley Units 1 and 2 B 3.3.3-16

PAM Instrumentation B 3.3.3 Table B 3.3.3-1 (page 1 of 1)

Post Accident Monitoring Instrumentation

_I PAM INSTRUMENTATION RCS Hot Leg Temperature (Wide Range)

RCS Cold Leg Temperature (Wide Range)

RCS Pressure (Wide Range)

Steam Generator (SG) Water Level Refueling Water Storage Tank Level Containment Pressure (Narrow Range)

Pressurizer Water Level Steam Line Pressure Auxiliary Feewater Flow Rate RCS Subcooling Margin Monitor Containment Water Level (Wide Range)

Core Exit Temperature Reactor Vessel Level Indicating System Condensate Storage Tank Level Containment Area Radiation (High Range)

TPNS TE-413, TE-423, TE-433 TE-41 0, TE-420, TE-430 PT-402, PT-403 Wide Range - LT-477, LT-487, LT-497 Narrow Range - LT-474, LT-475, LT-476 LT-484, LT-485, LT-486 LT-494, LT-495, LT-496 LT-501, LT-502 PT-950, PT-951, PT-952, PT-953 LT-459, LT-460, LT-461 PT-474, PT-475, PT-476 PT-484, PT-485, PT-486 PT-494, PT-495, PT-496 FT-3229A, FT-3229B, FT-3229C Q0 (2) Hi1 NGCCM2523A&B LT-3594A, LT-3594B TE-2301 - TE-2351 LE-2352, LE-2353 LT-515, LT-516 I

RE-27A, RE-27B Farley Units 1 and 2 B 3.3.3-17

Hydrogen Recombiners B 3.6.7 DELETED additional pages deleted:

B 3.6.7-2 B 3.6.7-3 B 3.6.7-4 B 3.6.7-5 B 3.6.7-6 Farley Units I and 2 B 3.6.7-1

HMS B 3.6.8 B 3.6 CONTAINMENT SYSTEMS B 3.6.8 Hydrogen Mixing System (HMS)

BASES The HMS reduces the potential for breach of containment due to a hydrogen oxygen reaction by providing a uniformly mixed post accident containment atmosphere, thereby minimizing the potential for local hydrogen burns due to a pocket of hydrogen above the flammable concentration.

The post accident HMS is an Engineered Safety Feature (ESF) and is designed to withstand a loss of coolant accident (LOCA) without loss of function. The System has two independent trains, each consisting of two fans with their own motors and controls. Each train is sized for 15,000 cfm. The two trains are initiated automatically on a Safety Injection signal. Each train is powered from a separate emergency power supply. Since a single fan can provide 100% of the mixing requirements, the System will provide its design function with a limiting single active failure.

Air is drawn from the steam generator compartments by the locally mounted mixing fans and is discharged toward the upper regions of the containment. This complements the air patterns established by the containment air coolers, which take suction above the operating floor level and discharge to the lower regions of the containment, and the containment spray, which cools the air and causes it to drop to lower elevations. The systems work together such that potentially stagnant areas where hydrogen pockets could develop are eliminated.

When performing their post accident hydrogen mixing function, the hydrogen mixing fans are designed to prevent motor overload in a post accident high pressure environment. The design flow rate is based on the minimum air distribution requirements to eliminate stagnant hydrogen pockets. Each train is redundant (in excess of full required capacity) and is powered from an independent ESF bus.

Farley Units 1 and 2 B 3.6.8-1

HMS B 3.6.8 BASES LCO by a Safety Injection signal. Only one fan per train is required (continued)

OPERABLE for the train to be considered OPERABLE.

Operation with at least one HMS fan provides the mixing necessary to ensure uniform hydrogen concentration throughout containment.

APPLICABILITY In MODES 1 and 2, the two HMS trains ensure the capability to prevent localized hydrogen concentrations above the flammability limit of 4.0 volume percent in containment assuming a worst case single active failure.

In MODE 3 or 4, both the hydrogen production rate and the total hydrogen produced -after a LOCA would be less than that calculated for the DBA LOCA. Also, because of the limited time in these MODES, the probability of an accident requiring the HMS is low.

Therefore, the HMS is not required in MODE 3 or 4.

In MODES 5 and 6, the probability and consequences of a LOCA or steam line break (SLB) are reduced due to the pressure and temperature limitations in these MODES. Therefore, the HMS is not required in these MODES.

ACTIONS A.1 With one HMS train inoperable, the inoperable train must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE HMS train is adequate to perform the hydrogen mixing function. However, the overall reliability is reduced because a single failure in the OPERABLE train could result in reduced hydrogen mixing capability, although the capacity of a single fan is sufficient to provide adequate mixing. The 30 day Completion Time is based on the availability of the other HMS train, the small probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability limit), the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit, and the availability of the Containment Spray System and the Post Accident Hydrogen Purge System.

(continued)

I Farley Units 1 and 2 B 3.6.8-3

HMS B 3.6.8 BASES ACTIONS A.1 (continued)

Required Action A.1 has been modified by a Note that states the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when one HMS train is inoperable. This allowance is based on the availability of the other HMS train, the small probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability limit), and the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit.

B.1 and B.2 With two HMS trains inoperable, the ability to perform the hydrogen control function via alternate capabilities must be verified by administrative means within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The alternate hydrogen control capability is provided by the containment Post Accident Hydrogen Purge System. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time allows a reasonable period of time to verify that a loss of hydrogen control function does not exist. Both the initial verification and all subsequent verifications may be performed as an administrative check, by examining logs or other information to determine the availability of the alternate hydrogen control system. It does not mean to perform the Surveillances needed to demonstrate OPERABILITY of the alternate hydrogen control system. If the ability to perform the hydrogen control function is maintained, continued operation is permitted with two HMS trains inoperable for up to 7 days. Seven days is a reasonable time to allow two HMS trains to be inoperable because the hydrogen control function is maintained and because of the low probability of the occurrence of a LOCA that would generate hydrogen in the amounts capable of exceeding the flammability limit.

C.1 If an inoperable HMS train cannot be restored to OPERABLE status within the required Completion Time, 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 at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-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.

(continued)

Farley Units 1 and 2 B 3.6.8-4

HMS B 3.6.8 BASES (continued)

SURVEILLANCE SR 3.6.8.1 REQUIREMENTS Operating each HMS train for > 15 minutes ensures that each train is OPERABLE and that all associated controls (including starting from the control room) are functioning properly. It also ensures that blockage, fan and/or motor failure, or excessive vibration can be detected for corrective action. While this system is not included in the scope of the Inservice Testing (IST) Program, the 92 day Frequency is consistent with IST Program Surveillance Frequencies, operating experience, the known reliability of the fan motors and controls, and the two train redundancy available.

SR 3.6.8.2 Verifying that each HMS fan speed is 2 1320 rpm ensures that each train is capable of maintaining localized hydrogen concentrations below the flammability limit. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 1 8 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

SR 3.6.8.3 This SR ensures that each HMS train responds properly'to a Safety Injection actuation signal. The Surveillance verifies that each fan starts from the nonoperating condition. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES

1. Deleted

2. Deleted

3. Regulatory Guide 1.7, Revision 1.

4. WCAP 7901, Revision 1.

I I

Farley Units 1 and 2 B 3.6.8-5

Reactor Cavity Hydrogen Dilution System B 3.6.9 B 3.6 CONTAINMENT SYSTEMS B 3.6.9 Reactor Cavity Hydrogen Dilution System (RCHDS)

BASES BACKGROUND The RCHDS reduces the potential for breach of containment due to a hydrogen oxygen reaction by providing a uniformly mixed post accident containment atmosphere, thereby minimizing the potential for local hydrogen burns due to a pocket of hydrogen above the flammable concentration.

The post accident RCHDS is an Engineered Safety Feature (ESF) and is designed to withstand a loss of coolant accident (LOCA) without loss of function. The System has two independent trains, each consisting of one fan with its own motor and controls. Each train is sized for 270 cfm (Unit 1) and 1570 cfm (Unit 2).

The two trains are initiated automatically on a Safety Injection signal.

Each train is powered from a separate emergency power supply.

Since each train fan can provide 100% of the mixing requirements, the System will provide its design function with a limiting single active failure. The RCHDS ventilates the reactor cavity to ensure that this volume is available for the dilution of containment hydrogen, and to maintain hydrogen concentrations in this volume in equilibrium with that of the remainder of the containment. The RCHDS fans discharge into the reactor cavity through a circular header embedded in the cavity wall at an elevation approximately coincident with that of the lower reactor vessel head. The RCHDS discharge flows from the cavity upward around the reactor vessel and outward through the incore instrument chase. The RCHDS fans take suction from the periphery of the containment just below the operating floor. The design flow rate is based on the minimum air distribution requirements to eliminate stagnant hydrogen pockets. The RCHDS and Hydrogen Mixing System work together such that potentially stagnant areas where hydrogen pockets could develop are eliminated.

(continued)

Farley Units 1 and 2 B 3.6.9-1

Reactor Cavity Hydrogen Dilution System B 3.6.9 BASES APPLICABILITY In MODE 3 or 4, both the hydrogen production rate and the total (continued) hydrogen produced after a LOCA would be less than that calculated for the DBA LOCA. Also, because of the limited time in these MODES, the probability of an accident requiring the RCHDS is low.

Therefore, the RCHDS is not required in MODE 3 or 4.

In MODE 5 or 6, the probability and consequences of a LOCA or steam line break (SLB) are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RCHDS is not required in these MODES.

ACTIONS A.1 With one RCHDS train inoperable, the inoperabale train must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE RCHDS train is adequate to perform the hydrogen mixing function. However, the overall reliability is reduced because a single failure in the OPERABLE train could result in reduced hydrogen mixing capability. The 30 day Completion Time is based on the availability of the other RCHDS train, the small probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability limit), the amount of time available after a LOCA or SLB (should one occur) or operator action to prevent hydrogen accumulation from exceeding the flammability limit, and the availability of the Containment Spray System and the Post Accident Venting System.

Required Action A.1 has been modified by a Note that states the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when one RCHDS train is inoperable. This allowance is based on the availability of the other RCHDS train, the small probability of a LOCA or SLB occurring (that would generate an amount of hydrogen that exceeds the flammability limit), and the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit.

B.1 If an inoperable RCHDS train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a (continued)

Farley Units 1 and 2 B 3.6.9-3

Reactor Cavity Hydrogen Dilution System B 3.6.9 BASES ACTIONS B.1 (continued)

MODE in which the LCO does not apply. To achieve this status, the plant. must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-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.

SURVEILLANCE SR 3.6.9.1 REQUIREMENTS Operating each RCHDS train for > 15 minutes ensures that each train is OPERABLE and that all associated controls are functioning properly and that each fan may be started by operator action from the control room. It also ensures that blockage, fan and/or motor failure, or excessive vibration can be detected for corrective action. While this system is not included in the scope of the Inservice Testing (IST)

Program, the 92 day Frequency is consistent with IST Program Surveillance Frequencies, operating experience, the known reliability of the fan motors and controls, and the two train redundancy available.

SR 3.6.9.2 This SR ensures that each RCHDS train responds properly to a Safety Injection signal. The Surveillance verifies that each fan starts from the non-operating condition. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES

1. Deleted

2. Deleted

3. Regulatory Guide 1.7, Revision 0.

I I

Farley Units 1 and 2 B 3.6.9-4 Edwin I. Hatch Nuclear Plant Joseph M. Farley Nuclear Plant Vogtle Electric Generating Plant Application for Technical Specification Amendment to Eliminate Requirements for Hydrogen Recombiners and Hydrogen and Oxygen Monitors Using the Consolidated Line Item Improvement Process VEGP Marked-up and Clean Typed TS and Bases Pages

TABLE OF CONTENTS (continued) 3.6 CONTAINMENT SYSTEMS.....................................................

3.6.1-1 3.6.1 Containment.....................................................

3.6.1-1 3.6.2 Containment Air Locks....................................................

3.6.2-1 3.6.3 Containment Isolation Valves.....................................................

3.6.3-1 3.6.4 Containment Pressure....................................................

3.6.4-1 3.6.5 Containment Air Temperature....................................................

3.6.5-1 3.6.6 Containment Spray and Cooling Systems.............................................

3.6.6-1 3..I

-eleboners 3.6.7-1 3.7 PLANT SYSTEMS.............................................

3.7.1-1 3.7.1 Main Steam Safety Valves (MSSVs).............................................

3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs)..............................................

3.7.2-1 3.7.3 Main Feedwater Isolation Valves (MFIVs) and Main Feedwater Regulation Valves (MFRVs) and Associated Bypass Valves..

3.7.3-1 3.7.4 Atmospheric Relief Valves (ARVs).....................................................

3.7.4-1 3.7.5 Auxiliary Feedwater (AFW) System.....................................................

3.7.5-1 3.7.6 Condensate Storage Tank (CST) - (Redundant CSTs).........................

3.7.6-1 3.7.6a Condensate Storage Tank (CST) - (Non-redundant CSTs)..........

3.7.6a-1 3.7.7 Component Cooling Water (CCW) System...........................................

3.7.7-1 3.7.8 Nuclear Service Cooling Water (NSCW) System..................................

3.7.8-1 3.7.9 Ultimate Heat Sink (UHS)....................................................

3.7.9-1 3.7.10 Control Room Emergency Filtration System (CREFS) - Both Units Operating.........

3.7.10-1 3.7.11 Control Room Emergency Filtration System (CREFS) - One Unit Operating........

3.7.11-1 3.7.12 Control Room Emergency Filtration System (CREFS) - Both Units Shutdown.........

3.7.12-1 3.7.13 Piping Penetration Area Filtration and Exhaust System (PPAFES)...........

3.7.13-1 3.7.14 Engineered Safety Features (ESF) Room Cooler and Safety Related Chiller System.3.7.14-1 3.7.15 Fuel Storage Pool Water Level.3.7.15-1 3.7.16 Secondary Specific Activity.3.7.16-1 3.7.17 Fuel Storage Pool Boron Concentration.3.7.17-1 3.7.18 Fuel Assembly Storage in the Fuel Storage Pool.3.7.18-1 (continued)

Vogtle Units 1 and 2 iii Amendment No. 107 (Unit 1)

Amendment No.

85 (Unit 2)

PAM Instrumentation 3.3.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H.

(continued)

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

Applicable to those functions with only one required channel per loop, SG, or steam line.

One channel inoperable and no diverse channel OPERABLE.

i. Two HydPOgRn Monitorsl

.4 Restore one onr to l

l inoorabl.

l lOPERABLE status.

l EI-\\

NOTE----------

Not applicable to Containment Radiation and RVLIS functions.

.1 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Required Action and associated Completion Time of Condition H i not met.

J/Ii 1-

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

Applicable to Containment Radiation and RVLIS functions only.

Initiate action in accordance with Specification 5.6.8.

Immediately Required Action and asociated Completion Time of Condition H not met.

Vogtle Units 1 and 2 3.3.3-4 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 1 of 1)

Post Accident Monitonng Instrumentation FUNCTION

1. Reactor Coolant System (RCS) Pressure (wide range)

2. RCS Th, (wide range)

3. RCS Tw (wide range)

4. Steam Generator (SG) Water Level (wide range)

5. SG Water Level (narrow range)

6. Pressurizer Level

7. Containment Pressure

8. Steam line Pressure

9. Refueling Water Storage Tank (RWST) Level

10. Containment Normal Sumps Level (narrow range)

11. Containment Water Level (wide range)

12. Condensate Storage Tank Level

13. Auxiliary Feedwater Flow

14. Containment Radiation Level (high range)

15. Steam line Radiation Monitor

16. RCS Subcooling Dl

7.

Neutron Flux (extended range)

E'eactor Vessel Water Level (RVLIS)

19.

5

20. Containment Pressure (extended range)

21. Containment Isolation Valve Position

22. Core Exit Temperature - Quadrant 1

23. Core Exit Temperature - Quadrant 2

24. Core Exit Temperature - Quadrant 3

25. Core Exit Temperature - Quadrant 4 REQUIRED CHANNELS 2

1/loop 1/loop 1/SG 2/SG 2

2 2/steam line 2

2 2

2/tank(')

2/SG 2

1/steam line 2

2 2

2 2/penetration flow path0') ()

2(d) 2(d) 2(d) 2(d)

CONDITIONS B,GH,g B,G,HII 1

B,G.HJGM 13 B.G,H,S3s B,G,H,'

B,G,HA B,G,H,1 B,G,H,MiI 13 B,G,H, 1

B,G,H,1 X

B,G,H,1 BG,H, M B,G,H,E B,GH,H, B,G,H,fi BG,H,E3' BAG.H,1" B,G,H,13 BAGH,13 (a)

Only required for the OPERABLE tank.

(b)

Not required for Isolation valves whose associated penetration is Isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.

Applicable for containment Isolation valve position Indication designated as post-accident monitoring Instrumentation (containment Isolation valves which receive containment Isolation phase A or containment ventilation isolation signals).

(c)

Only one position Indication channel is required for penetration flow paths with only one Installed control room Indication channel.

(d)

A channel consists of two core exit thermocouples (CETs).

Vogtle Units 1 and 2 3.3.3-6 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

DELETED I

Hydrogen Recombiners 3.6.7 Vogtle Units 1 and 2 3.6.7-1 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Hydrogen Recombiners 3.6.7 Vogtle Units 1 and 2 3.6.7-2 Amendment No. 96 (Unit 1)

Amendment No. 74 (Unit 2)

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.6 Reactor Coolant System (RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR) (continued)

3.

Letter from C. I. Grimes, NRC, to R. A. Newton, Westinghouse Electric Corporation, "Acceptance for Referencing of Topical Report WCAP-1 4040, Revision 1, 'Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves, "' October 16, 1995.

4.

Letter from C. K. McCoy, Georgia Power Company, to U.S. Nuclear Regulatory Commission, Attention: Document Control Desk, "Vogtle Electric Generating Plant, Pressure and Temperature Limits Report," Enclosures 1 and 2, January 26, 1996.

d.

The PTLR shall be provided to the NRC upon issuance for each reactor vessel fluence period and for any revision or supplement thereto.

5.6.7 EDG Failure Report If an individual emergency diesel generator (EDG) experiences four or more valid failures in the last 25 demands, these failures and any nonvalid failures experienced by that EDG in that time period shall be reported within 30 days.

Reports on EDG failures shall include the information recommended in Regulatory Guide 1.9, Revision 3, Regulatory Position C.4, or existing Regulatory Guide 1.108 reporting requirement.

5.6.8 PAM Reoort When a Report is required by Condition G or [g of LCO 3.3.3, "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.

(continued)

Vogtle Units 1 and 2 5.6-5 Amendment No. 117 (Unit 1)

Amendment No.

95 (Unit 2)

TABLE OF CONTENTS 3.6 CONTAINMENT SYSTEMS...........................

3.6.1-1 3.6.1 Containment.....................................................

3.6.1-1 3.6.2 Containment Air Locks 3.6.2-1 3.6.3 Containment Isolation Valves....................................................

3.6.3-1 3.6.4 Containment Pressure 3.6.4-1 3.6.5 Containment Air Temperature 3.6.5-1 3.6.6 Containment Spray and Cooling Systems

........................... 3.6.6-1 3.6.7 Deleted.....................................................

3.6.7-17 3.7 PLANT SYSTEMS..........................

3.7.1-1 3.7.1 Main Steam Safety Valves (MSSVs) 3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs) 3.7.2-1 3.7.3 Main Feedwater Isolation Valves (MFIVs) and Main Feedwater Regulation Valves (MFRVs) and Associated Bypass Valves....

3.7.3-1 3.7.4 Atmospheric Relief Valves (ARVs)....................................................

3.7.4-1 3.7.5 Auxiliary Feedwater (AFW) System....................................................

3.7.5-1 3.7.6 Condensate Storage Tank (CST) - (Redundant CSTs)

................. 3.7.6-1 3.7.6a Condensate Storage Tank (CST) - (Non-redundant CSTs)...............

3.7.6a-1 3.7.7 Component Cooling Water (CCW) System

.......................... 3.7.7-1 3.7.8 Nuclear Service Cooling Water (NSCW) System

..................... 3.7.8-1 3.7.9 Ultimate Heat Sink (UHS) 3.7.9-1 3.7.10 Control Room Emergency Filtration System (CREFS) - Both Units Operating 3.7.10-1 3.7.11 Control Room Emergency Filtration System (CREFS) - One Unit Operating 3.7.11-1 3.7.12 Control Room Emergency Filtration System (CREFS) - Both Units Shutdown.

3.7.12-1 3.7.13 Piping Penetration Area Filtration and Exhaust System (PPAFES) 3.7.13-1 3.7.14 Engineered Safety Features (ESF) Room Cooler and Safety Related Chiller System 3.7.14-1 3.7.15 Fuel Storage Pool Water Level 3.7.15-1 3.7.16 Secondary Specific Activity 3.7.16-1 3.7.17 Fuel Storage Pool Boron Concentration

.3.7.17-1 3.7.18 Fuel Assembly Storage in the Fuel Storage Pool

.3.7.18-1

.(continued)

Vogtle Units 1 and 2 iii Amendment No.

(Unit 1)

Amendment No.

(Unit 2)

PAM Instrumentation 3.3.3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME H.

(continued)

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

Applicable to those functions with only one required channel per loop, SG, or steam line.

One channel inoperable and no diverse channel OPERABLE.

I-

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

1.1 Be in MODE 4.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Not applicable to Containment Radiation and RVLIS functions.

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

J.

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

J.1 Initiate action in accordance Immediately Applicable to with Specification 5.6.8.

Containment Radiation and RVLIS functions only.

Required Action and asociated Completion Time of Condition H not met.

I I

I Vogtle Units 1 and 2 3.3.3-4 Amendment No.

Amendment No.

(Unit 1)

(Unit 2)

PAM Instrumentation 3.3.3 Table 3.3.3-1 (page 1 of 1)

Post Accident Monitonng Instrumentation FUNCTION

1. Reactor Coolant System (RCS) Pressure (wide range)

2.

RCS Tta (wide range)

3. RCS Tad (wide range)

4. Steam Generator (SG) Water Level (wide range)

5.

SG Water Level (narrow range)

6. Pressurizer Level

7. Containment Pressure

8.

Steam line Pressure

9. Refueling Water Storage Tank (RWST) Level

10. Containment Normal Sumps Level (narrow range)

11. Containment Water Level (wide range)

12. Condensate Storage Tank Level

13. Auxiliary Feedwater Flow

14. Containment Radiation Level (high range)

15. Steam line Radiation Monitor

16. RCS Subcooling

17. Neutron Flux (extended range)

18. Reactor Vessel Water Level (RVLIS)

19. Deleted

20. Containment Pressure (extended range)

21. Containment Isolation Valve Position

22. Core Exit Temperature -Quadrant 1

23. Core Exit Temperature - Quadrant 2

24. Core Exit Temperature -Quadrant 3

25. Core Exit Temperature - Quadrant 4 REQUIRED CHANNELS 2

c1loop 1/loop 1/SG 2/SG 2

2 2/steam line 2

2 2

2ttank"')

2/SG 2

1/steam line 2

2 2

2 2/penetration flow path(b) 2(d) 2(d) 2(d) 2(d CONDITIONS BAG.HI CGHI DAGHI EGHJI BG.HI B,G,H,I B,G,H,I B,G,H,I BAGHJI B.G,H,I BGH,I B,G.HI BGHI BG,H,J F,G.H.I BG,HI B.GHI B.GH,J BG,HI B.GHI BAGRH.I BGH,I BGHI B,G,HI (a)

Only required for the OPERABLE tank.

(b)

Not required for isolation valves whose associated penetration is Isolated by at least one closed and deactivated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured.

Applicable for containment Isolation valve position indication designated as post-accident monitoring Instrumentation (containment isolation valves which receive containment Isolation phase A or containment ventilation isolation signals).

(c)

Only one position Indication channel is required for penetration flow paths with only one Installed control room indication channel.

(d)

A channel consists of two core exit thermocouples (CETs).

Vogtle Units 1 and 2 3.3.3-6 Amendment No.

Amendment No.

(Unit 1)

(Unit 2)

Hydrogen Recombiners 3.6.7 DELETED Vogtle Units 1 and 2 3.6.7-1

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.6 Reactor Coolant System (RCS) PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR) (continued)

3.

Letter from C. I. Grimes, NRC, to R. A. Newton, Westinghouse Electric Corporation, "Acceptance for Referencing of Topical Report WCAP-14040, Revision 1, 'Methodology Used to Develop Cold Overpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves, '" October 16, 1995.

4.

Letter from C. K. McCoy, Georgia Power Company, to U.S. Nuclear Regulatory Commission, Attention: Document Control Desk, "Vogtle Electric Generating Plant, Pressure and Temperature Limits Report," Enclosures 1 and 2, January 26, 1996.

d.

The PTLR shall be provided to the NRC upon issuance for each reactor vessel fluence period and for any revision or supplement thereto.

5.6.7 EDG Failure Report If an individual emergency diesel generator (EDG) experiences four or more valid failures in the last 25 demands, these failures and any nonvalid failures experienced by that EDG in that time period shall be reported within 30 days.

Reports on EDG failures shall include the information recommended in Regulatory Guide 1.9, Revision 3, Regulatory Position C.4, or existing Regulatory Guide 1.108 reporting requirement.

5.6.8 PAM Report When a Report is required by Condition G or J of LCO 3.3.3, "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.

(continued)

Vogtle Units 1 and 2 5.6-5 Amendment No.

(Unit 1)

Amendment No.

(Unit 2)

TABLE OF CONTENTS (continued)

B 3.4 REACTOR COOLANT SYSTEM (RCS)........................................

B 3.4.1-1 B 3.4.1 B 3.4.2 B 3.4.3 B 3.4.4 B 3.4.5 B 3.4.6 B 3.4.7 B 3.4.8 B 3.4.9 B 3.4.1 0 B 3.4.11 B 3.4.12 B 3.4.13 B 3.4.14 B 3.4.15 B 3.4.16 B 3.5 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits........................................

RCS Minimum Temperature for Criticality......................................

RCS Pressure and Temperature (P/T) Limits................................

RCS Loops -

MODES 1 and 2......................................................

RCS Loops -

MODE 3..................................................................

RCS Loops -

MODE 4..................................................................

RCS Loops -

MODE 5, Loops Filled.............................................

RCS Loops -

MODE 5, Loops Not Filled.......................................

Pressurizer....................................................................................

Pressurizer Safety Valves..............................................................

Pressurizer Power Operated Relief Valves (PORVs).....................

Cold Overpressure Protection Systems (COPS)............................

RCS Operational LEAKAGE..........................................................

RCS Pressure Isolation Valve (PIV) Leakage................................

RCS Leakage Detection Instrumentation.......................................

RCS Specific Activity.....................................................................

EMERGENCY CORE COOLING SYSTEMS (ECCS)...................

B 3.4.1-1 B 3.4.2-1 B 3.4.3-1 B 3.4.4-1 B 3.4.5-1 B 3.4.6-1 B 3.4.7-1 B 3.4.8-1 B 3.4.9-1 B 3.4.10-1 B 3.4.1 1-1 B 3.4.12-1 B 3.4.13-1 B 3.4.14-1 B 3.4.15-1 B 3.4.16-1 B 3.5.1-1 B 3.5.1 Accumulators.

B 3.5.2 ECCS - Operating.

B 3.5.3 ECCS - Shutdown.

B 3.5.4 Refueling Water Storage Tank (RWST).

B 3.5.5 Seal Injection Flow.

B 3.5.6 Recirculation Fluid pH Control System.

B 3.6 CONTAINMENT SYSTEMS.

B 3.6.1 Containment.

B 3.6.2 Containment Air Locks.

B 3.6.3 Containment Isolation Valves.

B 3.6.4 Containment Pressure.

B 3.6.5 Containment Air Temperature.

B 3.6.6 Containment Spray and Cooling Systems (Atmospheric and Dual).

B 3.6.7

!Hv dFGQ n R oo m

hiRe I

Deleted-]~

B 3.5.1-1 B 3.5.2-1 B 3.5.3-1 B 3.5.4-1 B 3.5.5-1 B 3.5.6-1 B 3.6.1-1 B 3.6.1-1 B 3.6.2-1 B 3.6.3-1 B 3.6.4-1 B 3.6.5-1 B 3.6.6-1 B 3.6.7-1 I

(continued)

Vogtle Units 1 and 2 ii Rev. 1-3/99

PAM Instrumentation B 3.3.3 BASES LCO

18.

Reactor Vessel Water Level (continued)

Reactor Vessel Water Level (LT1 310, LT1 311, LT1 312, LT1 320, LT1 321, & LT1 322) is provided for verif ication and long term surveillance of core cooling. It is also used for accident diagnosis and to determine reactor coolant inventory adequacy.

A RVLIS channel consists of Full Range, Upper Range, and Dynamic Range transmitters. LT1310 and LT1 320 are Upper Range, LT1311 and LT1321 are Full Range, and LT1312 and LT1 322 are Dynamic Range.

The Reactor Vessel Water Level Monitoring System provides a direct measurement of the collapsed liquid level above the uppercore plate. The collapsed level represents the amount of liquid mass that is in the reactor vessel above the core.

Measurement of the collapsed water level is selected because it is a direct indication of the water inventory.

49.

HvdFGqeR Monitors HydFogon Monitors (Loops 12070 & 12080) arc provided to detect high hydrogeR concentration conditions that Fepresent-a potential for containment broach from a hydrogen explosion.

This variable is also important in verifying the adequacy of mnitigating actionsF.

21.

Containment Isolation Valve Position CIV Position is provided for verification of Containment OPERABILITY, and Phase A isolation.

When used to verify Phase A isolation, the important information is the isolation status of the containment penetrations. The LCO requires one channel of valve position indication in the control room to be OPERABLE for each active containment isolation valve in a containment penetration flow path, i.e., two total channels of containment isolation valve position indication for a penetration flow path with two active valves. This is sufficient to redundantly verify the isolation status of each isolable penetration either via indicated status of the active valve, as applicable, and prior knowledge of a passive valve, or via system boundary status. If a normally active CIV is known to be closed and deactivated, position (continued)

Vogtle Units 1 and 2 B 3.3.3-12 Rev. 1-6/03

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued) 14 Condition I applies when two hydrogen monitor channels are inoperable. Required Action 1.1 requiroe restoring one hydrogen monitor channel to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months GGF (Wh npletieR Timo is reasonable because it is uRlikely that a LOCA ich would causo core damage) would occur during this time.

I If the Required Action and associated Completion Time of L

~Jl Editins H 3 are not met and Table 3.3.3-1 directs entry into Condition A, the unit must be brought to a MODE where the requirements of this LCO do not apply. To achieve this status, the unit must be brought to at least MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The allowed Completion Time is reasonable, based on operating xperience, to reach the required unit conditions from full power co ns in an orderly manner and without challenging unit systems.

Condition R is modified by a Note that excludes the Containment Radiation and RVLIS Functions. These Functions are addressed by another Condition.

J Alternate means of monitoring Reactor Vessel Water Level (RVLIS) and Containment Area Radiation are available. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. If these alternate means are used, the Required Action is not to shut down the unit but rather to follow the directions of Specification 5.6.8, in the Administrative Controls section of the TS. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas (continued)

Vogtle Units 1 and 2 B 3.3.3-17 Rev. 1-11/01

PAM Instrumentation B 3.3.3 BASES ACTIONS 9.1 (continued) in which they are not equivalent, and provide a schedule for restoring

~the normal PAM channels; SURVEILLANCE A Note has been added to the SR Table to clarify that SR 3.3.3.1 REQUIREMENTS and SR 3.3.3.2 apply to each PAM instrumentation Function in Table 3.3.3-1.

SR 3.3.3.1 Performance of the CHANNEL CHECK once every 31 days ensures that a gross instrumentation failure has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar unit instruments located throughout the unit.

Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. If the channels are within the criteria, it is an indication that the channels are OPERABLE.

The Frequency of 31 days is based on operating experience that demonstrates that channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the LCO required channels.

(continued)

Vogtle Units 1 and 2 B 3.3.3-1 8 Revision No. 0

I DELETED Hydrogen Recombiners B 3.6.7 BW6

' NT INMEN SYST MS B3..7 H yrogen ecom ners

/ASE

/

//

BA KGROUVND Tle/functj/n of th/hydrog reco biners to eli nate thpoten ial

/ each i

conta ment de to a hydroge oxygen eactioy Per 1 CFR 6.44, "94tadard4fr Co 4ustiblGas Cpntrol S tems in ht-Wa 6r-Cool d Reactors" (Ret. 1), anIdGDC 41, "Con inment At osphe Clea p" (Ref. 2), hyd bgen re ombin rs are r quired t duce tD hydro en cor~ientratiof in the ntainrent foil wing a lss f cool htacci!

nt(LO A)ors amline reak LB). T e recor iners ccomplVh this b recoin ning h rogen nd oxy n to

/

formater vzpor. T e vapor emains ncont inment hus eli mating an discha ge to t envirop ent. The hydj gen re ombine are rpanually itiatednince fi mable mmits wduld no e reacd untild everal ays aftr a Des) n Basi Accider t (DBA.

/ TwoXO% cppacity I epend 4t hydr gen re mbiner ystem are pro ided.

ach con ists of controls cated the co rol bulling, a p

er su py, and recompner. gecombi ationis ccomp shedby eating ghydrogn air mi ure abve 11 §OF. Th resulti water vapor disch rge ga ss are.ooled pior to di charge rom the recorpbiner.

single r combiper is caable of aintal g the hydrogen copcentrat in cgntainmqnt below/ e 4.1 y'lume percent (v~,) flam mbility lim t. Twg recoin ersareprovided to me t'the rpquiremfidt for re undancy and ipIependefce. E bh reco biner is owere Vf rom a separat 'Engiy red Sa ty Feaares bus and is provid with a epara 6pow paneld contr pan

/l A PLICALE

/e hydr gen re oibine/s provi for th apab'Il AFE ANALYES controll g the lk hydy gen co centrat6 n in co; inment o less than tbe lowe flammable conc ntratio of 4.1 vio followir~

g a DB This ontrol ould p event a ontain ent-widP hydroge6 burn, tpus en ring t press re and t mperatLfre assuyed in th analys are ed.

tin DBA r rative to ydrog ene n is a (contined)

Vogtle Units 1 and 2 B 3.6.7-1 Revision No. 0

Hydrogen Recombiners B 3.6.7 BA$ES

/

PPL ABL H Irogen ay 8CC ulate~ icont 4ment f'Iowing LOCAs a AF YA ALY S r sultof:

conti ed) 7

a.

etal team re ction b een e zirco urm fuel od cla ding nd the eactooolant/

b.

Rad lytic de, ompos onof aterine Reac r Cool nt Syst (R )and he coninmen rump; /

c.

ydrog etnthe yCSat etime ftheL A(i.e.,hydrogen dissolv d in th reactor coolant nd hyd 6 gen gs in the, pres srizerv orspa e);or C rosion f metal/expos to con mine t spray nd

/

erge2 y Core oolina ystem olution

/

To, aluate he pot ntial for ydroge accu ulationj contai. ment fo lowing a'LOCA, he hydr gen geleratioq as a fupction of (me f,llowing4he initi tion of I e accid nt is cfculated. Conse ative assumptions reomme ed by Ieferen 3 are 'sed to aximiz the amou t of hydrogen ca culated/

B ed on the cons vative ssumpJ ons us d to cal late th droger concen ation vsus tirij6 after XLOCA, J e hydr gen oncenration inte primnry con inmenpwould reach3%v/o abou 6 day after th LOCA d 4.0 about 2 daysater if n recomb/ner was nctioni g (Ref..

Initiaing th fiydrogef recomf)iners wpen

,the rimar ontainrrent hydfogen c,5ncentra) on reaches 3.5 yJo will njrintain to? hydro bn con entrati in the trimary ntainmnt below

/ /

/

,,ri~ammab Ilty limitsf

/

The h drogen ecombners ar designg such at, with te con rvative calcul ted hy ogen g9fheratio rates di cussed above, a s~igle rec mbine is cap76Ie of Ii n~Iting the eak hy rogen /

c ncentra) on in ntainm nt to les than 4 v/o (Rf. 3). Th6 ydroge Purg ystenyis similafy desi ed suc that one 0f two

/redund nt trai is an -dequatebackup o the re undant pydrogen reco iners.

/

Thlhydro en rec 1biners atisfy riterion f10C 50.36

/ /

/

j9)( (2)(ii//)

//

7

/

//

/

continu/d)

Vogtle Units 1 and 2 B 3.6.7-2 Rev. 1-10/01

Hydrogen Recombiners B 3.6.7 li tb (Contin ea)

/

0 7T a hydro n rec biners lust b OPERA BLE. T~his ens es erationlfeat eatone idroge recomi er in the event f a wo t

/ /

/

,/rc~ase single ac 7 6ealuy'

/

/ Operion wi at lea one h rogen ecombi er ensu s that e X

o}LCfyroge cnce tratio ~n be heete ~

m e eedinX

/

/ /

ths~~flamm,#bility lirWt

/

APP ESAIL'and a hd 4gen re mbiner/are r uired tcotl Iyf rog n co i

It fl

/ Control th ydra n conc ntratia within ntainm nt belo its flainmability,

/ / it of 4. v/o foowing a OCA/

suminra wor case s gle faile.

/InMOES3 hd4 bl hthe hyrogen producti nrate ndthe tpal hydr gen pr uced eraLOC A be le sthan hat calcu ated forte DBILOCA./Also, bgause a the li ti myln these1 r IODES, he prob bility of n accid nt reqI ring th hydrog

/

combi ers is I1N. The fore, th hydra en rec binersare not requir in MODE 3 or 4' In DES and 6, he prabbility apd cons uence of a LO A are a, due t the prepsure an tempefature Ii itations n these fODE erfor hydr

~n reco biner re no quired thes ODES AC~T 1NS A /

lith on cantalent h iragen ecombi r nop able, th noper le reco biner ust be estore 'o OPE ABLE status wit~rn 30 d In t Con ion, th remainirg OPE ABLE h Irogen,

rec biner i adequate ta rform th, hydragen contr I functio.

H ever, toe averyI reliab ity is reg ced b use a ingle fai re in t

OPE BLE 6combi ner couldfIesult i/uce ydroge control

//apabili.

The0 day ompletiofi Timei based n the av ilability f

,the atr hydr gen re mbinerthe sin I probaity of a CAr SLB ccurrin (that 7ould ge rate a amoun f hydroaen that exc eds th flami ility limit), and Pie amou t of time availabl after a

CA qSLB (§ ould a occur)4or oper tar actia.to prev nt droge accu latioanf exc~edingth flamma lity lmi (c/ntind Vogtle Units 1 and 2 B 3.6.7-3 Revision No. 0

Hydrogen Recombiners B 3.6.7 CTI NS A (conti ed/)

RequireActioA.1 ha een odified y a NoIthat sta es the provisjns of 0 3.0k are n applic le. As result,,4 MOD char)e isalf wed w en one ecombjher is in perable/ This allowance sd based n the ailabit' of the the hy rogen r

ombin r, the s all pro ability f a LOCA or SLyoccurri g (that Iould g nerate en amorp t of hy rogen at exce ds the fammag lity limit), afid the tnount ttime t

aiable Sfter a L¢CA orSLB (s 6uld one qCcur) fo/operat r actio toprevt hydro en ac Omulati n from excdeding3te flam ability 1 it.

1 andB.2

/

I /ldlrogen r combin rsinop able, t e abili toperfo the hy rogen go6ntrol f ction vA altern te cap ilities 91 st be v rified b m

ns withj) I hour The ernate hydrogen contro

,aaiieare Wrvidedby the cftanmn Hyd gen Pug Syste/Contment DilutoI.

The)

Cp letio Time allows reason ble peri of tir4 to vefly that eI oss of hyd ogen c ntrol fu rjtion do s not 9*ist.

I vradditio (the alt nate h

rogen ontrol s stem cwability ust be/verified very 12 ours ereaft to ens e its co tinuedavailabylty. Bot he initi I verifi t on andII subsv uent 6 rificati hs may le perfo ed as d

n admin 9strative heckb exami inglogF orother nform ionto det mine th availa4Iity of t.e alter te hydr gen cogrol syst m. It does not m an to p dorm te Surveillances r other esting n,eeded to t Jemonst e OPE ABILI of th0 malternat hydro n contryl system If the a~blity to p dorm t e hydr~en con ol funcpion is m iintained, contin d oper ion is ermitte with tw hydro 6n reco biners inop able for p to 7 ays.

even da s is a r sonabl time to low two ydroge recorpners eino rable cause ehydrogen control fun ion ispynaintai rd and 4ecause jf the 10 probabi ity of the tcurren of a 4OCA tht would eneratV hydrog in the,founts capable f exc ding te flamm ility lit.

/

(continied r

j Vogtle Units 1 and 2 B 3.6.7-4 Revision No. 0 Vogtle Units 1 and 2 B 3.6.7-4 Revision No. 0

Hydrogen Recombiners B 3.6.7 BAPES,

( ntinu d) e !noerable hydrog reco nfiiner(s) nnot lr restor d to

/OPER LE stitus wit hn the re uired ompletin Time,/te pla must e brought to a ODE i which }he LCO,does no~apply. Xo achi ye this tatus, e plant must b~brough to at leaIt MOE3 wit in 6 hoirs. Th Comp tion Ti rreof 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is riasona te, bas o opera ing exp e'riencep reach l0ODE from fujl powe conditi s

/

an or erly m Aner and witho challe ging p syste s.

SUFIVEILLANCE SK"3.6.7 RJEQUIR ENTS

/

Perfor ance o0a syst functi nal test or eac hydrogn reco biner esures re recor iners e oper tional 96d can am an ustain he tem eraturey ecess ry for h drogen ecombi ation.

In articul r, this verifie that th minim m heat r sheat tempera re incr ases to 700°Fjf

90 inutes After r ching

/00F, e pow r is incr ased to axim m pow for ap oximat y min tes an power i verifie obe 0 kW.

O rating /perien ehas s wn that these ompon nts us Ilypas t

Surve lance,ten pe rmed the 1 month Ffequen

herefqfe, the F quenc was c hclude to be a eptabi from a

/reliabiity standoint.

S 3..7.

Tis eSnsrei there re no pysical p blems at coul affect recon)biner op ration. Since e reco iners e mech/nically pasqVe, they re no subject omech nical fazure. Th only cr ible failfre invol es los of pow r, block e of the interna flow, mi tile pact, et A visu inspe ion is s fficient deter me abn mal cor itions t t could cause chfail res. Th 18mo thFreq ency forjhis SR s

devyloped nsidera1ig the i idence f hydro en reco biners fling th R in e p s low.

cntinu d Vogtle Units 1 and 2 B 3.6.7-5 Revision No. 0

Hydrogen Recombiners B 3.6.7 Vogtle Units 1 and 2 B 3.6.7-6 Revision No. 0

TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS)........................................

B 3.4.1-1 B 3.4.1 B 3.4.2 B 3.4.3 B 3.4.4 B 3.4.5 B 3.4.6 B 3.4.7 B 3.4.8 B 3.4.9 B 3.4.10 B 3.4.11 B 3.4.12 B 3.4.13 B 3.4.14 B 3.4.15 B 3.4.16 B 3.5 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits........................................

RCS Minimum Temperature for Criticality......................................

RCS Pressure and Temperature (PIT) Limits.................................

RCS Loops - MODES 1 and 2......................................................

RCS Loops - MODE 3..................................................................

RCS Loops -

MODE 4..................................................................

RCS Loops -

MODE 5, Loops Filled.............................................

RCS Loops - MODE 5, Loops Not Filled.......................................