Text

Amergen Request for Amendment to Technical Specifications to Eliminate Requirements for Hydrogen Recombiners and Hydrogen/Oxygen Monitors Using the Consolidated Line Item Improvement Process
	ML042660189
Person / Time
Site:	Dresden, Peach Bottom, Byron, Braidwood, Clinton, Quad Cities, LaSalle
Issue date:	09/15/2004
From:	Jury K; AmerGen Energy Co, Exelon Generation Co, Exelon Nuclear
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RS-04-141
	Download: ML042660189 (163)
	v • d • e

Amer@snSM Exekrn.

An Exelon Company www.exeloncorp.com Nucl ear AmerGen Energy Company, LLC 4300 Winfield Road Exelon Generation Warrenville, IL 60555 4300 Winfield Road Warrenville, IL 60555 RS-04-141 10 CFR 50.90 September 15, 2004 U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001 Braidwood Station, Units 1 and 2 Facility Operating License Nos. NPF-72 and NPF-77 NRC Docket Nos. STN 50-456 and STN 50-457 Byron Station, Units 1 and 2 Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455 Clinton Power Station Facility Operating License No. NPF-62 NRC Docket No. 50-461 Dresden Nuclear Power Station, Units 2 and 3 Facility Operating License Nos. DPR-19 and DPR-25 NRC Docket Nos. 50-237 and 50-249 LaSalle County Station, Units 1 and 2 Facility Operating License Nos. NPF-1 1 and NPF-1 8 NRC Docket Nos. 50-373 and 50-374 Peach Bottom Atomic Power Station, Units 2 and 3 Facility Operating License Nos. DPR-44 and DPR-56 NRC Docket Nos. 50-277 and 50-278 Quad Cities Nuclear Power Station, Units 1 and 2 Facility Operating License Nos. DPR-29 and DPR-30 NRC Docket Nos. 50-254 and 50-265

Subject:

Request for Amendment to Technical Specifications to Eliminate Requirements for Hydrogen Recormbiners and Hydrogen/Oxygen Monitors Using the Consolidated Line Item Improvement Process In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit," Exelon Generation Company, LLC (EGC) and AmerGen Energy Company, LLC (AmerGen) are requesting an amendment to Appendix A, Technical Specifications (TS) of the Facility Operating Licenses listed above. The proposed amendment will delete the TS requirements related to hydrogen recombiners and hydrogen/oxygen monitors. The proposed

September 15, 2004 U. S. Nuclear Regulatory Commission Page 2 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 changes are consistent with Revision 1 of NRC-approved Industry/Technical Specifications 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 (68 FR 55416) on September 25, 2003, as part of the consolidated line item improvement process (CLIIP).

The attached amendment request is subdivided as shown below.

Attachment 1 provides a description of the proposed changes and confirmation of applicability.

Attachments 2A - 2G include the marked-up TS pages for the stations listed above.

Attachments 3A - 3G include the associated typed TS pages with the proposed changes incorporated for the stations listed above.

Attachments 4A - 4G include the marked-up TS Bases pages for the stations listed above.

The TS Bases pages are provided for information only, and do not require NRC approval.

Attachments 5A - 5G include the regulatory commitments for the stations listed above.

EGC and AmerGen request approval of the proposed change by March 31, 2005, with the amendment being implemented within 120 days of issuance.

The proposed amendment has been reviewed by the Plant Operations Review Committees at each of the stations and approved by their respective Nuclear Safety Review Boards in accordance with the requirements of the EGC and AmerGen Quality Assurance Programs.

EGC and AmerGen are notifying the State of Illinois and the Commonwealth of Pennsylvania of this application for a change to the TS by sending a copy of this letter and its attachments to the designated officials in accordance with 10 CFR 50.91, "Notice for public comment; State consultation."

Should you have any questions concerning this letter, please contact Ms. Alison M. Mackellar at (630) 657-2817.

I declare under penalty of perjury that the foregoing is true and correct. Executed on the 15th day of September.2004.

Keith R. Jury Director, Licensing and Regulatory Affairs Exelon Generation Company, LLC AmerGen Energy Company, LLC

September 15, 2004 U. S. Nuclear Regulatory Commission Page 3 : Evaluation of Proposed Changes A: Markup of Proposed Technical Specifications Changes for Braidwood B: Markup of Proposed Technical Specifications Changes for Byron C: Markup of Proposed Technical Specifications Changes for Clinton D: Markup of Proposed Technical Specifications Changes for Dresden E: Markup of Proposed Technical Specifications Changes for LaSalle F: Markup of Proposed Technical Specifications Changes for Peach Bottom G: Markup of Proposed Technical Specifications Changes for Quad Cities A: Typed TS pages with proposed changes incorporated for Braidwood B: Typed TS pages with proposed changes incorporated for Byron C: Typed TS pages with proposed changes incorporated for Clinton D: Typed TS pages with proposed changes incorporated for Dresden E: Typed TS pages with proposed changes incorporated for LaSalle F: Typed TS pages with proposed changes incorporated for Peach Bottom G: Typed TS pages with proposed changes incorporated for Quad Cities A: Markup of TS Bases pages with changes indicated for Braidwood B: Markup of TS Bases pages with changes indicated for Byron C: Markup of TS Bases pages with changes indicated for Clinton D: Markup of TS Bases pages with changes indicated for Dresden E: Markup of TS Bases pages with changes indicated for LaSalle F: Markup of TS Bases pages with changes indicated for Peach Bottom G: Markup of TS Bases pages with changes indicated for Quad Cities A: Regulatory Commitments for Braidwood B: Regulatory Commitments for Byron C: Regulatory Commitments for Clinton D: Regulatory Commitments for Dresden E: Regulatory Commitments for LaSalle F: Regulatory Commitments for Peach Bottom G: Regulatory Commitments for Quad Cities

September 15, 2004 U. S. Nuclear Regulatory Commission Page 4 cc: Regional Administrator - NRC Region I Regional Administrator - NRC Region IlIl NRC Senior Resident Inspector- Braidwood Station NRC Senior Resident Inspector - Byron Station NRC Senior Resident Inspector - Clinton Power Station NRC Senior Resident Inspector - Dresden Nuclear Power Station NRC Senior Resident Inspector - LaSalle County Station NRC Senior Resident Inspector - Peach Bottom Atomic Power Station NRC Senior Resident Inspector - Quad Cities Nuclear Power Station

September 15, 2004 U. S. Nuclear Regulatory Commission Page 5 bcc: Project Manager, NRR - Braidwood Station Project Manager, NRR - Byron Station Project Manager, NRR - Clinton Power Station Project Manager, NRR - Dresden Nuclear Power Station Project Manager, NRR - LaSalle County Station Project Manager, NRR - Peach Bottom Atomic Power Station Project Manager, NRR - Quad Cities Nuclear Power Station Illinois Emergency Management Agency - Division of Nuclear Safety Director, Bureau of Radiation Protection - Pennsylvania Department of Environmental Resources Manager of Energy Practice - Winston & Strawn Site Vice President - Braidwood Station Site Vice President - Byron Station Site Vice President - Clinton Power Station Site Vice President - Dresden Nuclear Power Station Site Vice President - LaSalle County Station Site Vice President - Peach Bottom Atomic Power Station Site Vice President - Quad Cities Nuclear Power Station Regulatory Assurance Manager - Braidwood Station Regulatory Assurance Manager - Byron Station Regulatory Assurance Manager - Clinton Power Station Regulatory Assurance Manager - Dresden Nuclear Power Station Regulatory Assurance Manager - LaSalle County Station Regulatory Assurance Manager - Peach Bottom Atomic Power Station Regulatory Assurance Manager - Quad Cities Nuclear Power Station Director, Licensing and Regulatory Affairs Manager, Licensing - Braidwood, Byron and LaSalle County Stations Manager, Licensing - Clinton, Dresden and Quad Cities Power Stations Manager, Licensing - Peach Bottom Atomic Power Station Nuclear Licensing Administrator - Braidwood, Byron, Clinton, Dresden, LaSalle, Peach Bottom and Quad Cities Exelon Document Control Desk Licensing (Hard Copy)

ATTACHMENT I EVALUATION OF PROPOSED CHANGE INDEX

1.0 INTRODUCTION

2.0 DESCRIPTION

OF PROPOSED AMENDMENT

3.0 BACKGROUND

4.0 REGULATORY REQUIREMENTS AND GUIDANCE

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

6.1 Verification and Commitments 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION 8.0 ENVIRONMENTAL EVALUATION 9.0 PRECEDENT

10.0 REFERENCES

1.0 INTRODUCTION

In accordance with 10 CFR 50.90, "Application for amendment of license or construction permit," Exelon Generation Company, LLC (EGC) and AmerGen Energy Company, LLC (AmerGen) are requesting an amendment to Appendix A, Technical Specifications (TS) for the following operating licenses.

Facility Operating Plant License Nos..

Braidwood Station, Units 1 and 2 NPF-72 and NPF-77 Byron Station, Units 1 and 2 NPF-37 and NPF-66 Clinton Power Station, Unit 1 NPF-62 Dresden Nuclear Power Station, Units 2 and 3 DPR-19 and DPR-25 LaSalle County Station, Units 1 and 2 NPF-1 1 and NPF-1 8 Peach Bottom Atomic Power Station, Units 2 and 3 DPR-44 and DPR-56 Quad Cities Nuclear Power Station, Units 1 and 2 DPR-29 and DPR-30 The proposed amendment deletes TS requirements related to hydrogen recombiners and references to the hydrogen and oxygen monitors. 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/oxygen monitors resulted in numbering and formatting changes to other TS, which were otherwise unaffected by this proposed amendment.

The proposed change is consistent with NRC-approved Industry/Technical Specifications Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-447, Revision 1, "Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors." The availability of this TS improvement through the consolidated line item improvement process (CLIP) was announced in the Federal Register on September 25, 2003.

2.0 DESCRIPTION

OF PROPOSED AMENDMENT Consistent with the NRC-approved Revision 1 of TSTF-447, the proposed TS changes include the following:

Braidwood Station, Units I and 2 TS Section 3.3.3.F Hydrogen Monitor Deleted TS Table 3.3.3-1 Item 15, Deleted "Post Accident Monitoring Hydrogen Monitors Instrumentation" TS Section 3.6.8 Hydrogen Recombiners Deleted Page 2 of 6

Byron Station, Units I and 2 TS Section 3.3.3.F Hydrogen Monitor Deleted TS Table 3.3.3-1 Item 15, Deleted "Post Accident Monitoring Hydrogen Monitors Instrumentation" TS Section 3.6.8 Hydrogen Recombiners Deleted Clinton Power Station TS Table 3.3.3.1-1 Item 8, Deleted "Post Accident Monitoring Drywell and Containment Instrumentation" H2 & 02 Analyzer TS Section 3.6.3.1 Hydrogen Recombiners Deleted Dresden Nuclear Power Station, Units 2 and 3 TS Table 3.3.3.1-1 Item 7, Drywell H2 Deleted "Post Accident Monitoring Concentration Analyzer Instrumentation" and Monitor TS Table 3.3.3.1-1 Item 8, Drywell 02 Deleted "Post Accident Monitoring Concentration Analyzer Instrumentation" and Monitor LaSalle County Station, Units 1 and 2 TS Table 3.3.3.1-1 Item 7, Drywell 02 Deleted "Post Accident Monitoring Concentration Analyzer Instrumentation" and Monitor TS Table 3.3.3.1-1 Item 8, Drywell H2 Deleted "Post Accident Monitoring Concentration Analyzer Instrumentation" and Monitor TS Section 3.6.3.1 Hydrogen Recombiners Deleted TS Section 3.8.1 AC Sources - Operating Deleted requirement for hydrogen recombiners TS Section 3.8.7 Distribution Systems- Deleted requirement for Operating hydrogen recombiners TS Section 5.5 Primary Coolant Sources Modified requirement for Outside Containment controls to minimize leakage from hydrogen recombiner cooling penetrations when a future modification will eliminate penetrations as a potential leakage path.

I Page 3 of 6

Peach Bottom Atomic Power Station, Units 2 and 3 TS Table 3.3.3.1-1 Item 9, Drywell H2 & 02 Deleted "Post Accident Monitoring Analyzer Instrumentation" TS Table 3.3.3.1-1 Item 10, Suppression Deleted "Post Accident Monitoring Chamber H2 & 02 Instrumentation" Analyzer Quad Cities Nuclear Power Station, Units I and 2 Table 3.3.3.1-1 Item 7, Drywell H2 Deleted "Post Accident Monitoring Concentration Analyzer and Instrumentation" Monitor Table 3.3.3.1-1 Item 8, Drywell 02 Deleted "Post Accident Monitoring Concentration Analyzer and Instrumentation" Monitor TS changes included in this application are Limiting Condition for Operation (LCO), surveillance requirements, renumbering and formatting changes that resulted directly from the deletion of the above requirements related to hydrogen recombiners, hydrogen and oxygen monitors.

LaSalle County Station, Units I and 2 TS currently include an administrative requirement for a program, "Primary Coolant Sources Outside Containment," to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during a transient or accident. At LaSalle County Station, the hydrogen recombiner cooling system falls under the scope of this requirement. Since a modification, if executed, may not be completed during the implementation period of this amendment, the TS for the Primary Coolant Sources Outside Containment program is being revised to add a parenthetical phrase following the associated listing for hydrogen recombiners. The phrase will state that the TS requirements would continue to apply until such time as a modification eliminates the hydrogen recombiner penetrations as a potential leakage path. This change provides clarification of the intent that the programmatic requirements of the Primary Coolant Sources Outside Containment program will continue to apply until the hydrogen recombiners are eliminated as a potential leakage path.

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.

The TS bases pages are provided for information only, and do not require NRC approval.

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 REQUIREMENTS 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), TSTF-447, the documentation associated with the 10 CFR 50.44 rulemaking, and other related documents.

Page 4 of 6

5.0 TECHNICAL ANALYSIS

EGC and AmerGen have reviewed the safety evaluation (SE) published on September 25, 2003, (68 FR 55416), as part of the CLIIP Notice of Availability. This verification included a review of the NRC's SE, as well as the supporting information provided to support TSTF-447.

EGC and AmerGen have concluded that the justifications presented in the TSTF proposal and the safety evaluation prepared by the NRC are applicable to the Braidwood, Byron, Clinton, Dresden, LaSalle, Peach Bottom and Quad Cities Stations and justify this amendment for the incorporation of the changes to the applicable TS.

6.0 REGULATORY ANALYSIS

A description of these proposed changes and the relationship to 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.

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, EGC and AmerGen are making the following verifications and regulatory commitments.

EGC and AmerGen are not proposing any variations or deviations from the requirements of the STS changes described in TSTF-447, Revision 1 or the NRC's model safety evaluation dated September 25, 2003. In accordance with the NRC's safety evaluation, the hydrogen and oxygen monitoring capability will be maintained but no longer considered safety related as defined in 10 CFR 50.2, 'Definitions."

1. EGC and AmerGen have verified that a hydrogen monitoring system capable of diagnosing beyond design basis accidents is currently installed at Braidwood Station Units 1 and 2, Byron Station Units 1 and 2, Clinton Power Station Unit 1, Dresden Nuclear Power Station Units 2 and 3, LaSalle County Station Units 1 and 2, Peach Bottom Atomic Power Station Units 2 and 3, and Quad Cities Nuclear Power Station Units 1 and 2 and are making a regulatory commitment to maintain such a monitoring capability; The hydrogen monitors will be included in a licensee controlled document or program identified in Attachments 5A - 5G.

This regulatory commitment will be implemented by the implementation date.

2. Braidwood Station Units 1 and 2, Byron Station Units 1 and 2, and Clinton Power Station Unit I do not have inerted containments.

3. LaSalle County Station Units 1 and 2, Dresden Nuclear Power Station Units 2 and 3, Quad Cities Nuclear Power Station Units 1 and 2 and Peach Bottom Atomic Power Station Units 2 and 3 all have inerted containments. EGC has verified that an oxygen monitoring system capable of verifying the status of the inerted containment is installed at each of these plants and is making a regulatory commitment to maintain that capability. The oxygen monitors will be included in a licensee controlled document or program identified in Attachments 5A - 5G. This regulatory commitment will be implemented by the implementation date.

Page 5 of 6

7.0 NO SIGNIFICANT HAZARDS CONSIDERATION Exelon Generation Company, LLC (EGC) and AmerGen Energy Company, LLC (AmerGen) have reviewed the proposed No Significant Hazards Consideration Determination (NSHCD) published in the Federal Register as part of the CLIIP. EGC and AmerGen have concluded that the proposed NSHCD presented in the Federal Register notice (68 FR 55416) is applicable to Braidwood, Byron, Clinton, Dresden, LaSalle, Peach Bottom and Quad Cities Stations and is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91," paragraph (a),

"Notice for public comment."

8.0 ENVIRONMENTAL EVALUATION EGC and AmerGen have reviewed the environmental evaluation included in the model SE dated September 25, 2003 (68 FR 55416), as part of the CLIIP. EGC and AmerGen have concluded that the NRC's findings presented in that evaluation are applicable to Braidwood, Byron, Clinton, Dresden, LaSalle, Peach Bottom and Quad Cities Stations and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. EGC and AmerGen are not proposing variations or deviations from the TS changes described in TSTF-447, Revision 1 or the NRC's model SE published on September 25, 2003 (68 FR 55416).

10.0 REFERENCES

1. Technical Specifications Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-447, Revision 1, "Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors"

2. Federal Register, Volume 68, Number 186, "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," dated September 25, 2003 Page 6 of 6

ATTACHMENT 2-A Markup of Proposed Technical Specifications Page Changes BRAIDWOOD STATION REVISED TS PAGES 3.3.3-2 3.3.3-3 3.3.3-4 5.6-5 DELETED TS PAGES 3.6.8 (ALL)

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. As required by D.1 Restore one required 7 days Required Action A.1 channel to OPERABLE and referenced in status.

Table 3.3.3-1.

E. --------- NOTE--------E.1 Restore all but one 7 days Not appl icabcl to- required channel to F in 1OPERABLE status.

One or more Functions with two or more required channels inoperable.

F. Twec hydrogen monitor F.1 Retere one hydregen heus----

channel- inoperable. monitopr channel to

NOTE--------- AX1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Not applicable to Functions 11, 12, and ANfD

14. r-:

2 --------- NOTE --------

-Not applicable to Required Action and function 15.

associated Completion Time of Condition Dg E, or F not e.ffe Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to F. _v.e*ts_

(continued)

BRAIDWOOD - UNITS 1 & 2 3.3.3 - 2 Amendment 98

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

NOTE --------- Initiate action in Immediately Only applicable to accordance with Functions 11, 12, and Specification 5.6.7.

14.

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

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

Radiation detectors for Function 11, Containment Area Radiation, are excluded.

Perform CHANNEL CALIBRATION. 18 months BRAIDWOOD - UNITS 1 & 2 3.3.3 - 3 Amendment -9a-

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

Post kident Monitoring Instrunentation APPLICABLE KDIES OR OTHER SP'ECIFIED RfMCN CODIMSC1 F6IED OQMELS CONDITIMS

1. Reactor Coolant System (RCS) Pressure 1.2,3 2 B (Wide Range)

2. FES Hot Leg Temperature (Wide Range) 1.2.3 2 B

3. RCS Cold Leg Tenperature (Wide Range) 1,2,3 2 B

4. Steam Generator (SG) Water Level 1.2.3 1 D (Wide Range)(per SG)

5. SG Water Level (Narrow Range)(per SG) 1.2.3 1 D

6. Pressurizer Water Level (Narrcw Range) 1,2.3 2 B

7. Contaiment Pressure (Wide Range) 1,2.3 2 B

8. Steam Line Pressure (per SG) 1,2.3 2 B

9. Refueling Water Storage Tank Water Level 1,2,3 2 B

10. Containment Floor Water Level (Wide Range) 1.2.3 2 B

11. Containment Area Radiation (High Range) 1.2.3 1 0

12. Main Steam Line Radiation (per steam line) 1.2.3 1 D

13. Core Exit Temperature (per core quadrant) 1,2,3 4 B

14. Reactor Vessel Water Level 1,2.3 2 B

15. IIb gen ibmiteps 1,2 B BRAIDWOOD - UNITS 1 & 2 3.3.3 - 4 Affendment,991"

Iydrgegen Reccmbiners-3.6.8 3.6 CONTAINMENT SYSTEMS 3.6.8 Hydrogen Recombine 2F ( De-leir-c) 0 3.6.8 Two hydirogen recombiners shall be OPERABLE.

APPLICA LITY: MODES 1 and 2.

ACTIONS CONDITi REQUIRED ACTION X PLETION TIME A. One hydrogen A.1 --------NOTE--------

recombiner inopera e.LCO 3.0.4 is not applicable.

\Restore hy en30 days

\ recombine to

\ PERABE status.

B. Two hydrogen B.1 by 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months recombiners admirn rative means inoperable. that the ydrogenAN D control fution is maintained. Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.2 Restore one hydrogen -days recombiner to OPERABLE status.

C. Requ e Action and C.1 Be in MODE 3. 6-hours as ciated Completion m not met.

BRAIDWOOD - UNITS 1 & 2 3.6.8 ,- 4mndment.7.1111"

IIydrogen Recmbinefs e.6.8

'SUKEILLANCE REQUIREMENTS . _,-"

SURVEILLANCE NCY SR 3.6.8.1 system functional test for 18 months hydrogen bner.

SR 3.6.8.2 Visually examine e en recombiner 18 months enclosure and ify there i s evidence of abno onditions.

SR 3.6.8 Perform a resistance to ground test for s each heater phase.

mmAT LI!

ml 1^A^

,1I&TTr urtdI.

' 0

+/-.4.e Lt n n a

% n f en me4 !1J5

'tIi

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

a. RCS pressure and temperature limits for heat up, cooldown, low temperature operation, criticality, and hydrostatic testing as well as heatup and cooldown rates, and Power Operated Relief Valve (PORV) lift settings shall be established and documented inthe PTLR for the following:

LCO 3.4.3, "RCS Pressure and Temperature (P/T) Limits," and LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP)

System";

b. -The analytical methods used to determine the.RCS pressure and temperature limits shall be those previously reviewed and approved by,the NRC, specifically those described in NRC letter dated January 21, 1998, "Byron Station Units 1 and 2, and Braidwood Station, Units 1 and 2, Acceptance for Referencing of Pressure Temperature Limits Report"; and

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

5.6.7 Post Accident Monitoring Report When a report is required by Condition C orAKof 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.

BRAIDWOOD - UNITS 1 & 2 5.6 - 5 Amendment RZ

ATTACHMENT 2-B Markup of Proposed Technical Specifications Page Changes BYRON STATION REVISED TS PAGES 3.3.3-2 3.3.3-3 3.3.3-4 5.6-5 DELETED TS PAGES 3.6.8 (ALL)

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. As required by D.1 Restore one required 7 days Required Action A.1 channel to OPERABLE and referenced in status.

Table 3.3.3-1.

E. --------- NOTE--------- E.1 Restore all but one 7 days Nbt appeliceict required channel to IVIe Ie-1i-- OPERABLE status.

One or more Functions with two or more required channels inoperable.

F. Two hydragen niter F.1 Restore en --

APhPAdren he -

channelinoperable. monitor channel to

-6PERABLEstatus.-

F --------- NOTE --------- X Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Not applicable to Functions 11, 12, and AND

14. F.

- -------- NOTlE-------

-Not applicable to Required Action and Function1-5.--

associated Completion Time of Condition D.,or E.-er-F not met. Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued)

BYRON - UNITS 1 & 23 3.3.3 - 2 Amendment ),

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION [_COMPLETION TIME

NOTE--------- M.1 Initiate action in Immediately Only applicable to accordance with Functions 11, 12, and Specification 5.6.7.

14.

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

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 --------------- =--NOTE--------------------

Radiation detectors for Function 11, Containment Area Radiation, are excluded.

Perform CHANNEL CALIBRATION. 18 months BYRON - UNITS 1 & 2 3.3.3 - 3 Amendment ;D6-"

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

Post Acaident Mcnitoring Instrrentation APFU(A3LL IiLk OR OTHER SPECIFIED R TIrCN CaNITIONS REOARED CMELS UTfTION-

1. Reactor Coolant System (FCS) Pressure 1,2.3 2 B (Wide Range)

2. RCS Hot Leg Tenperature (Wide Range) 1.2.3 2 B

3. RcS Cold Leg Temperature (Wide Range) 1,2.3 2 B

4. Steam Generator (SG) Water Level 1,2.3 1 D (Wide Range)(per SG)

5. SG Water Level (Narrow Range)(per SG) 1.2,3 D

6. Pressurizer Water Level (Narrcw Range) 1,2,3 2 B

7. Containment Pressure (Wide Range) 1.2,3 2 B

8. Steam Line Pressure (per SG) 1.2,3 2 B 2

9. Refueling Water Storage Tank Water Level 1,2.3 B 1,2,3 2

10. Containment Floor Water Level (Wide Range) B

11. Containment Area Radiation (High Range) 1.2.3 1 D

12. Main Steam Line Radiation (per steam line) 1.2.3 1 D

13. Core Exit Terperature (per core quadrant) 1,2.3 4 B

14. Reactor Vessel Water Level 1,2.3 2 B 1,2,3

*-.i_ *4,,^X+^__ 0 I Mr-j- - -- - - - -- - -, - -- - - - - V -

BYRON - UNITS 1 & 2 3.3.3 - 4 Amendment

Hydrgen Recombiners-I 3.6.8 3.6 CONTAINMENT SYSTEMS 3.6.8 Ilydrogen Rflccnbiners (1e~r-t-e.)

O 3.6.8 Two hydrogen recombiners shall be OPERABLE.

APPLICAB ITY: MODES 1 and 2.

ACTIONS CONDITI REQUIRED ACTION CO FETION TIME A. One hydrogen A.1 --------NOTE--

recombiner inoperabi LCO 3.0.4 isnot applicable.

Restore hyd gen 30 days

\recombi 0tt ERBL satus.

B. Two hydrogen B.1 V 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months recombiners dminist tive means inoperable. that the hdrogen. AD control func on is maintained. Once per

/ \ 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.2 Restore one hydrogen 7 s recombiner to OPERABLE status.

C. Req ed Action and C.1 .Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months a ciated Completion me not met.

I I BYRON - UNITS 1 & 2 3.6.8 - I Amendment

Hydrogen Recombiner 3.6 SURVEXLANCE REQUIREMENTS SURVEILLANCE FREQ Y SR 3.6.8.\ Perform a system functional test for each 18 mo s

\hydrogen recombiner.

SR 3.6.8.2 \ ually examine each hydrogen recombiner ; months elosure and verify there is no evidence ,

of normal conditions./

SR 3.6.8.3 Perform resistance to ground test for 18 months each hea&X phase.

N -X5IS1 & 3_. - __ Amndm

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

a. RCS pressure and temperature limits for heat up, cooldown, low temperature operation, criticality, and hydrostatic testing as well as heatup and cooldown rates, and Power Operated Relief Valve (PORV) lift settings shall be established and documented in the PTLR for the following:

LCO 3.4.3, "RCS Pressure and Temperature (P/T) Limits," and LCO 3.4.12, "Low Temperature Overpressure Protection (tTOP)

System";

b. The analytical methods used to determine the RCS pressure and temperature limits shall be those previously reviewed and approved by the NRC, specifically those described in NRC letter dated January 21, 1998, "Byron Station Units 1 and 2, and Braidwood Station, Units 1 and 2, Acceptance for Referencing of Pressure Temperature Limits Report"; and

c. 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 Post Accident Monitoring Report When a report is required ndition C or/of LCO 3.3.3, "Post Accident Monitoring (PAM) umentation," a report shall be submitted within the folli 14 days. The report shall outline the preplanned alternate i of monitoring, the cause of the inoperability, and the pit d schedule for restoring the instrumentation channels < Function to OPERABLE status.

BYRON - UNITS 1 & 2 5.6 - 5 Amendment JHr

ATTACHMENT 2-C Markup of Proposed Technical Specifications Page Changes CLINTON POWER STATION REVISED TS PAGES 3.3-21 3.3-22 DELETED TS PAGES 3.6-36 3.6-37

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 ---------------NOTE---------------------

Applicable for each Function in Table 3.3.3.1-1.

Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 ---- ---- NOTE ---------------------___-

Only applica Function 8 in Table Perform CHANNE IBRTd.

SR 3.3.3.1.3 --------------- NOTE---------------------

Applicable for each Function in Table 3.3.3.1-1 except Function 8.

Perform--CHANNEL-CA-I---ATION. -months Perform CHANNEL CALIBRATION. 18 months CLINTON 3.3 -21 Amendment No. ,

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

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

1. Reactor Steam Dome Pressure 2 E

2. Reactor Vessel Water Level 2 E

3. Suppression Pool Water Level

a. High Range 2 E

b. Low Range 2 E

4. Drywell Pressure 2 E

5. Primary Containment Area Radiation 2 F

6. Drywell Area Radiation 2 P

7. Penetration Flow Path, Automatic PCIV Position 2 per penetration E Mle-tA flow path ()(b)

S . Prwl &Ikl Gnsainmen_ .4 IQ.Z n...............

1y

9. Primary Containment Pressure

a. High Range 2 E

b. Low Range 2 E

10. Suppression Pool Water Bulk Average Temperature 2 (c) E I

(a) Not required for isolation valves whose associated penetration flow path is isolated.

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

(c) Monitoring each quadrant.

CLINTON 3.3-22 Amendment No. H

Primary Centainment H5IE]rzgen ReeembinRev 3.6.3.1 3.6 CONTAINMENT SY TEMS 3.6.3.1 Pt.-_ Cznt.ainmeet Hydregen Recombines 3.6.3.1 Two primary co ntainment hydrogen recombiners shall be OPERABLE.

.CAB : MODES 1 and 2.

A. One primary -------- NOTE --------

containment hydrog LCO 3.0.4 is not recombiner inoperabi applicable. /

Restore pr. 30 days containmen recombiner, B. Two primary 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months containment hydrogen recombiners inoperable.

AND B.2 Restore one primary\ 7 days containment hydrogen recbmbiner to OPERABLE status.

C. Requ ed Action and C.1 Be in MODE 3.

ass iated Completion T not met.

CLINTON 3.6-36 Amendment No. /

3.6.3.1 REQUIREMENTS SURVEILLANCE F

.1 form a system functional test for each 8 months pri containment hydrogen recombi

.2 visually examine e pr ry containment 18 months hydrogen recombiner sure and verify there is no evideRi of ab-R conditions.

.3 rform a resistance to ground test for onths

/ --

seach heater phase.

This poelfI fi o CLINTON 3.6-37 Amendment No. /

ATTACHMENT 2-D Markup of Proposed Technical Specifications Page Changes DRESDEN NUCLEAR POWER STATION REVISED TS PAGES 3.3.3.1-3 3.3.3.1-4

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS

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

1. These SRs apply to each Function in Table 3.3.3.1-1, except where identified in the SR.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the other required channel in the associated Function is OPERABLE.

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3.3.1:2 Perform CHANNEL CALIBRATION for 92 days Function/ 4.b, i7,and S.

SR 3.3.3.1.3 ------------------- NOTE------------------

For Function 2, not required for the transmitters of the channels.

Perform CHANNEL CALIBRATION for Functions 184 days 1 and 2.

SR 3.3.3.1.4 Perform CHANNEL CALIBRATION for Functions 12 months 3 and 9.

SR 3.3.3.1.5 Perform CHANNEL CALIBRATION for Functions 24 months 2, 4.a, 5, and 6.

Dresden 2 and 3 3.3.3. 1-3 Amendment No. *18Q

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

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

1. Reactor Vessel Pressure 2 E

2. Reactor Vessel Water Level

a. Fuel Zone (Wide Range) 2 E

b. Medium Range 2 E

3. Torus Water Level 2 E

4. Drywell Pressure a, Wide Range 2 E

b. Narrow Range 2 E

5. Drywell Radiation Monitors 2 F

6. Penetration Flow Path PCIV Position 2 per penetration E CoxIteter flow path(a)(b)

7. Torus11 11WaterT.mer Laelture ,2iEo, [

8. DBciiwes48 tnc0o Aiiel,.e a d6 P~lots £ E

9. Torus Water Temperature 2 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.

Dresden 2 and 3 3.3.3. 1-4 Amendment No. -45&/-46

ATTACHMENT 2-E Markup of Proposed Technical Specifications Page Changes LASALLE COUNTY STATION REVISED TS PAGES 3.3.3.1-3 3.3.3.1-4 3.8.1-1 3.8.7-1 5.5-2 DELETED TS PAGES 3.6.3.1 (ALL)

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS

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

1. These SRs apply to each Function in Table 3.3.3.1-1, exept wherc-identified in the SR.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the other required channel in the associated Function is OPERABLE.

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 Perfbrm IIANNEL CALIBRATION fer.

-fnctions 7 and B. (Ce_(eg1 LŽ SR 3.3.3.1.3 Perform CHANNEL CALIBRATION fo-r Funetions 24-months other than Functiens 7 and 8.

LaSalle 1 and 2 3.3.3. 1-3 Amendment No. ifl43

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

Post Accident Monitoring Instrumentation CONDITIONS REFERENCED REQUIRED FROM REQUIRED FUNCTION CHANNELS ACTION D.1 I.Reactor Steam Dome Pressure 2 E 2.Reactor Vessel Water Level

a. Fuel Zone 2 E

b. Wide Range 2 E 3.Suppression Pool Water Level 2 E 4.Drywell Pressure

a. Narrow Range 2 E

b. Wide Range 2 E 5.Primary Containment Gross Gamma Radiation 2 F 6.Penetration Flow Path PCIV Position 2 per penetration E flow path(a)(b) 7.Sujpess ez ConcentPationr empeaer 2

-- E- C(&Q_+X- )

8.81-2well Ha, Coneentration Afialyee K Ei-9.Suppression Pool Water Temperature 2 E (a) Not required for isolation valves whose associated penetration flow path is isolated by at least one closed and de-activated 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.

LaSalle I and 2 3.3.3.1-4 Amendment No. 44174-133.

xn_:

.1 J1

_ : m -;

r.- _ s-------- ; X J

I ----- ~ nA I--- vIrrr

_k: _ __

3.6.3.1 3.6 CONTAINMENT SYSTEMS 3.6.3.1 -Pri ar y r- ntair epegen ment 4fly fle e fi Bhi1q P CV)Oe- ci(

0 3.6.3.1 Two primary containment hydrogen recombinE shall be /rs OPERABLE.

APPLICABI TY: MODES 1 and 2.

ACTIONS CONDITIO\N REQUIRED ACTION COMPLETION TIME A. One primary A.1 -------- NOTE- ----

containment hydrogen LCO 3.0.4 i not recombiner inoperable. applicabli

\ -- -------- -

Rest e primary 30 days co ainment hydrogen combiner to OP ABLE status.

B. Two primary B Verify b 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months containment hydrogen administra ve means recombiners that the hyd gen AND inoperable. control functi is maintained. Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.2 Restore one primary 7 da containment hydrogen recombiner to OPERABLE status.

(continu )

LaSalle 1 and 2 3.6.3.1 -1 Amendment No. 147,'133

Primary Containment Hydrogen Recombiners 3.6.3.1 ACTIONS XNDITION REQUIRED ACTION COMPLETION ME C. Required ction and C.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associate Completion Time not me SURVEILLANCE REQUIREMENT / ___...

SU EILLANCE FREQUENCY SR 3.6.3.1.1 Perform a sy tem functional test f each 24 months primary conta ment hydrogen recot ner.

SR 3.6.3.1.2 Perform a resista e to groun test for 24 months each heater phase. A N 1 lle 1 and 2 3.6.3.1-2 Amendment No. 14 X3

AC Sources-Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources-Operating LCO 3.8.1 The following AC electrical power sources shall be OPERABLE:

a. Two qualified circuits between the offsite transmission network and the onsite Class IE AC Electric Power Distribution System;

b. Three diesel generators (DGs); and

c. The opposite unit's Division 2 DG capable of supporting the associated equipment required to be OPERABLE by Lbe . . 'P.ri y nte irrnnt Ileclrzj'n s lReembiners,"

LCO 3.6.4.3, "Standby Gas Treatment (SGT) System,"

LCO 3.7.4, "Control Room Area Filtration (CRAF) System,'

and LCO 3.7.5, "Control Room Area Ventilation Air Conditioning (AC) System."

APPLICABILITY: MODES 1, 2, and 3.

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

1. Division 3 AC electrical power sources are not required to be OPERABLE when High Pressure Core Spray (HPCS)

System is inoperable.

2. The opposite unit's Division 2 DG in LCO 3.8.1.c is not required to be OPERABLE when the associated required equipment is inoperable.

LaSalle I and 2 3.8.1-1 Amendment No. 147AtSY

Distribution Systems-Operating 3.8.7 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Distribution Systems-Operating LCO 3.8.7 The following electrical power distribution subsystems shall be OPERABLE:

a. Division 1 and Division 2 AC and 125 V DC distribution subsystems;

b. Division 3 AC and 125 V DC distribution subsystems;

c. Division 1 250 V DC distribution subsystem; and

d. The portions of the opposite unit's Division 2 AC and 125 V DC electrical power distribution subsystems capable of supporting the equipment required to be OPERABLE by LCO- .C.3.1, "`Pimary Ccntai-ment Hydregen-ReGmbimers," LCO 3.6.4.3, "Standby Gas Treatment (SGT)

System," LCO 3.7.4, "Control Room Area Filtration (CRAF)

System," LCO 3.7.5, "Control Room Area Ventilation Air Conditioning (AC) System," and LCO 3.8.1, "AC Sources-Operating."

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS

CONDITION REQUIRED ACTION COMPLETION TIME A. One or both Division 1 A.1 Restore Division 1 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months and 2 AC electrical and 2 AC electrical power distribution power distribution AND subsystems inoperable. subsystems to OPERABLE status. 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months from discovery of failure to meet LCO 3.8.7.a (continued)

LaSalle 1 and 2 3.8. 7-1 Amendment No. 147-+13-

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.1 Offsite Dose Calculation Manual (ODCM) (continued)

Each change shall be identified by markings in the margin of the affected pages, clearly indicating the area of the page that was changed, and shall indicate the date (i.e.,

month and year) the change was implemented.

5.5.2 Primary Coolant Sources Outside Containment This program provides controls to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to levels as low as practicable. The systems include the Low Pressure Core Spray, High Pressure Core Spray, Residual Heat Removal/,Low Pressure-Coolant Injection, Reactor Core Isolation Cooling,yel1odr-ogen rFecmbincr, prczess sampling (until such time as a moifiatin clmintcethe 1?nftP Airs~t~ ^ peppptration PASS 4 asE a potenta

'v'rrtfmr iHe-leakag pat), .et W it.K U. _. _ .a. ._v.._ .tndiy.L v ....X. "' .a .... .

The program shall include the following:

a. Preventive maintenance and periodic visual inspection requirements; and

b. Integrated leak test requirements for each system at 24 month intervals.

The provisions of SR 3.0.2 are applicable to the 24 month Frequency for performing integrated system'leak test activities.

5.5.3 Deleted.

(continued)

C(OAMfJ~ t.,cl Morrn, St Ga1s T nez, hrce v3 rechncieck 414p proCeSS rAp 5 (OtfigtSuCCA h-t~C CS 0.X Hif o? ci1i4 t kqcacis-L h , PASS pe.* a-s eo *,.dOt la to Psal LaSalle I and 2 5.5-2 Amendment No.-ie58,44

ATTACHMENT 2-F Markup of Proposed Technical Specifications Page Changes PEACH BOTTOM ATOMIC POWER STATION UNIT 2 REVISED TS PAGES 3.3-25 3.3-26 PEACH BOTTOM ATOMIC POWER STATION UNIT 3 REVISED TS PAGES 3.3-25 3.3-26

PAM Instrumentation 3.3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C Table 3.3.3.1-1 for not met. the channel.

E. As required by E.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Required Action D.1 and referenced in Table 3.3.3.1-1.

F. As required by F.1 Initiate action in Immediately Required Action D.1 accordance with and referenced in Specification 5.6.6.

Table 3.3.3.1-1.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK for each required 31 days PAM instrumentation channel.

SR 3.3.3.1.3 Perform CHANNEL CALIBRATION for each 24 months required PAM instrumentation channel cemccpt for the Drywcll and Supprc3ien Chamber Ha E O& Analyzers.

PBAPS UNIT 2 3.3-25 Amendment No.40-

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 Pressure 2 E

2. Reactor Vessel Water Level (Wide Range) 2 E

3. Reactor Vessel Water Level (Fuel Zone) 2 E

4. Su ppression Chamber Water Level (Wide Range) 2 E Drywell Pressure (Wide Range) 2 E

6. Drywell Pressure (Subatmospheric Range) 2 E

7. Drywell High Range Radiation 2 F B. PCIV Position 2 per penet(v~~fo E path fcItw 21 1I . rM r ?Aa,1 % Aml.___

11. Suppression Chamber Water Temperature 2(c) E

.r, (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 f low through the valve secured.

(b) Only one position Indication charnel is required for penetration flow paths with only one installed control room indication channel.

(c) Each charnel requires 10 resistance teaperature detectors (RTDs) to be OPERABLE with no two adjacent RTDs inoperable.

PBAPS UNIT 2 3.3-26 Amendment No.-Li-&

PAM Instrumentation 3.3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C Table 3.3.3.1-1 for not met. the channel.

E. As required by E.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Required Action D.1 and referenced in Table 3.3.3.1-1.

F. As required by F.1 Initiate action in Immediately Required Action D.1 accordance with and referenced in Specification 5.6.6.

Table 3.3.3.1-1.

., W -

7y_. -

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK for each required 31 days PAM instrumentation channel.

SR 3.3.3.1.3 Perform CHANNEL CALIBRATION for each 24 months required PAM instrumentation channel

t. A ._ L_. e

9 _ J excep forIII the Urywell one Suppression A oA Chamber 11 & 0 Analzers.

.. - _ a .. .. .,_ __ . .

PBAPS UNIT 3 3.3-25 Amendment No.-214-

f S

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 FUNCTICN CHANNELS ACTION D.1

1. Reactor Pressure 2 E

2. Reactor Vessel Water Level (Wide Range) 2 E

3. Reactor Vessel Water Level (Fuel Zone) 2 E

4. Suppression Chanber Water Level (Wide Range) 2 E

5. Drywell Pressure (Wide Range) 2 E

6. Drywell Pressure (Subatmospheric Range) 2 E

7. Drywell High Range Radiation 2 F

8. PCIV Position 2Iper penetc~~ fo E b_ erL6Tcb 9 vlt N, & O. l~ce 2r byp10. pression Char M, I 02. isr

11. Suppression Charber Water Temperature 2(c) 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) Each channel requires 10 resistance temperature detectors (RTDs) to be OPERABLE with no two adjacent RTDs inoperable.

PBAPS UNIT 3 3.3-26 Amendment No. -214-

ATTACHMENT 2-G Markup of Proposed Technical Specifications Page Changes QUAD CITIES NUCLEAR POWER STATION REVISED TS PAGES 3.3.3.1-3 3.3.3.1-4

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS

NOTEX -----------------------------------

1. These SRs apply to each Function in Table 3.3.3.1 1, exeept where-AiJdteid in the SR.r 4 When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the other required channel in the associated Function is OPERABLE.

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 Perferm GHAIMNEL CA6IBRATIOMI for H2,,,

Functions 7 and 8.

SR 3.3.3.1./2. Perform CHANNEL CALIBRATIONfer Functions 24 months other than Functions 7 and 8 Quad Cities I and 2 3.3.3. 1-3 Amendment No. 199,495-

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

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

1. Reactor Vessel Pressure 2 E

2. Reactor Vessel Water Level

a. Wide Range 2 E

b. Narrow Range 2 E

3. Torus Water Level 2 E

4. Drywell Pressure

a. Wide Range 2 E

b. Narrow Range 2 E

5. Drywell Radiation Monitors 2 F

6. Penetration Flow Path PCIV Position 2 per penetration E flow pathca)(b)

' Trusic 11, Tenemperatuen Pl 2leeyc

'EC End

0. B.,1iel 0, Ccieem laticm Aiilre ned Meito .

7.,P Torus Water Temperature 2 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.

-Quad Cities 1 and 2 3.3.3.1-4 Amendment No. 14949,495

ATTACHMENT 3-A Typed Pages for Technical Specifications Changes BRAIDWOOD STATION REVISED TS PAGES 3.3.3-2 3.3.3-3

.3.3.3-4 5.6-5 DELETED TS PAGES 3.6.8 (ALL)

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. As required by D.1 Restore one required 7 days Required Action A.1 channel to OPERABLE and referenced in status.

Table 3.3.3-1.

E. One or more Functions E.1 Restore all but one 7 days with two or more required channel to required channels OPERABLE status.

inoperable.

F. ---------NOTE--------- F.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Not applicable to Functions 11, 12, and AND 14.

F.2 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 D or E not met.

(continued)

BRAIDWOOD - UNITS 1 & 2 3.3.3 - 2 Amendment

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME G. --------- NOTE--------- G.1 Initiate action in Immediately I Only applicable to accordance with Functions 11, 12, and Specification 5.6.7.

14.

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

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

Radiation detectors for Function 11, Containment Area Radiation, are excluded.

Perform CHANNEL CALIBRATION. 18 months BRAIDWOOD - UNITS 1 & 2 3.3.3 - 3 Amendment

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

Post Accident Monitoring Instrumentation AWPLIABLL MI"Jh OR OTHER SPECIFIED RICTIcN WIDITIONS REQUIRED OWI4ELS CWDITIONS

1. Reactor Coolant System (RCS) Pressure 1,2,3 2 B (Wide Range)

2. RCS Hot Leg Temperature (Wide Range) 1,2,3 2 B

3. RCS Cold Leg Temperature (Wide Range) 1.2.3 2 B

4. Steam Generator (SG) Water Level 1,2,3 1 D (Wide Range)(per SG)

5. SG Water Level (Narrow Range)(per SG) 1.2,3 1 D

6. Pressurizer Water Level (Narrow Range) 1,2.3 2 B

7. Containment Pressure (Wide Range) 1,2,3 2 B

8. Steam Line Pressure (per SG) 1,2,3 2 B

9. Refueling Water Storage Tank Water Level 1,2,3 2 B

10. Containment Floor Water Level (Wide Range) 1.2,3 2 B

11. Containment Area Radiation (High Range) 1,2,3 I 0

12. Main Steam Line Radiation (per steam line) 1,2,3 1 D

13. Core Exit Temperature (per core quadrant) 1,2,3 4 B

14. Reactor Vessel Water Level 1,2,3 2 B BRAIDWOOD - UNITS 1 & 2 3.3.3 - 4 Arrendment

3.6.8 3.6 CONTAINMENT SYSTEMS 3.6.8 (Deleted)

BRAIDWOOD - UNITS 1 & 2 3.6.8-1 Amendment

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

a. RCS pressure and temperature limits for heat up, cooldown, low temperature operation, criticality, and hydrostatic testing as well as heatup and cooldown rates, and Power Operated Relief Valve (PORV) lift settings shall be established and documented in the PTLR for the following:

LCO 3.4.3, "RCS Pressure and Temperature (P/T) Limits," and LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP)

System";

b. The analytical methods used to determine the RCS pressure and temperature limits shall be those previously reviewed and approved by the NRC, specifically those described in NRC letter dated January 21, 1998, "Byron Station Units 1 and 2, and Braidwood Station, Units 1 and 2, Acceptance for Referencing of Pressure Temperature Limits Report"; and

c. 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 Post Accident Monitoring Report When a report is required by Condition C 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.

BRAIDWOOD - UNITS 1 & 2 5.6 - 5 Amendment

ATTACHMENT 3-B Typed Pages for Technical Specifications Changes BYRON STATION REVISED TS PAGES 3.3.3-2 3.3.3-3 3.3.3-4 5.6-5 DELETED TS PAGES 3.6.8 (ALL)

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. As required by D.1 Restore one required 7 days Required Action A.1 channel to OPERABLE and referenced in status.

Table 3.3.3-1.

E. One or more Functions E.1 Restore all but one 7 days with two or more required channel to required channels OPERABLE status.

inoperable.

F. --------- NOTE--------- F.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Not applicable to Functions 11, 12, and AND 14.

F.2 Be in MODE 4.

Required Action and associated Completion Time of Condition D or E not met. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (continued)

BYRON - UNITS 1 & 2 3.3.3 - 2 Amendment

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME G. --------- NOTE--------- G.1 Initiate action in Immediately I Only applicable to accordance with Functions 11, 12, and Specification 5.6.7.

14.

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

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

Radiation detectors for Function 11, Containment Area Radiation, are excluded.

Perform CHANNEL CALIBRATION. 18 months BYRON - UNITS 1 & 2 3.3.3 - 3 Amendment

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

Post Accident Monitoring Instnrumetation APPLICABLE MODES OR OTHER SPECIFIED FlCTION COtNITIO3S REQUIRED CHACNELS MIDITIONS

1. Reactor Coolant System (RCS) Pressure 1,2,3 2 B (Wide Range)

2. RCS Hot Leg Temperature (Wide Range) 1,2,3 2 B

3. RCS Cold Leg Temperature (Wide Range) 1.2,3 2 B

4. Steam Generator (SG) Water Level 1.2.3 1 D (Wide Range)(per SG)

5. SG Water Level (Narrow Range)(per SG) 1,2,3 1 D

6. Pressurizer Water Level (Narrow Range) 1,2,3 2 B

7. Containment Pressure (Wide Range) 1,2,3 2 B

8. Steam Line Pressure (per SG) 1.2,3 2 B

9. Refueling Water Storage Tank Water Level 1.2,3 2 B

10. Containment Floor Water Level (Wide Range) 1,2,3 2 B

11. Containment Area Radiation (High Range) 1,2.3 1 D

12. Main Steam Line Radiation (per steam line) 1,2,3 1 D

13. Core Exit Temperature (per core quadrant) 1,2,3 4 B

14. Reactor Vessel Water Level 1,2,3 2 B BYRON - UNITS 1 & 2 3.3.3 - 4 knendment

3.6.8 3.6 CONTAINMENT SYSTEMS 3.6.8 (Deleted)

BYRON - UNITS 1 & 2 3.6.8 - 1 Amendment

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

a. RCS pressure and temperature limits for heat up, cooldown, low temperature operation, criticality, and hydrostatic testing as well as heatup and cooldown rates, and Power Operated Relief Valve (PORV) lift settings shall be established and documented in the PTLR for the following:

LCO 3.4.3, "RCS Pressure and Temperature (P/T) Limits," and LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP)

System";

b. The analytical methods used to determine the RCS pressure and temperature limits shall be those previously reviewed and approved by the NRC, specifically those described in NRC letter dated January 21, 1998, "Byron Station Units 1 and 2, and Braidwood Station, Units 1 and 2, Acceptance for Referencing of Pressure Temperature Limits Report"; and

c. 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 Post Accident Monitoring Report When a report is required by Condition C 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.

BYRON - UNITS 1 & 2 5.6 - 5 Amendment

ATTACHMENT 3-C Typed Pages for Technical Specifications Changes CLINTON POWER STATION REVISED TS PAGES 3.3-21 3.3-22 DELETED TS PAGES 3.6-36 3.6-37

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 ----------- NOTE---------------------

Applicable for each Function in Table 3.3.3.1-1.

Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 Deleted SR 3.3.3.1.3 --------------- NOTE---------------------

Applicable for each Function in Table 3.3.3.1-1.

Perform__CHANNELCALI__RATION. _18_months I Perform CHANNEL CALIBRATION. 18 months CLINTON 3.3-21 Amendment No.

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

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

1. Reactor Steam Dome Pressure 2 E

2. Reactor Vessel Water Level 2 E

3. Suppression Pool Water Level

a. High Range 2 E

b. Low Range 2 E

4. Drywell Pressure 2 E

5. Primary Containment Area Radiation 2 F

6. Drywell Area Radiation 2 F

7. Penetration Flow Path, Automatic PCIV Position 2 per penetration E flow path (aCf

8. Deleted

9. Primary Containment Pressure I

a. High Range 2 E

b. Low Range 2 E

10. Suppression Pool Water Bulk Average Temperature 2 C) E (a) Not required for isolation valves whose associated penetration flow path is isolated.

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

(c) Monitoring each quadrant.

CLINTON 3.3 -22 Amendment No.

3.6.3 .1 3.6 CONTAINMENT SYSTEMS 3.6.3.1 Deleted CLINTON 3.66-36 Amendment No.

3.6.3.1 This page intentionally blank CLINTON 3 .6-37 Amendment No.

ATTACHMENT 3-D Typed Pages for Technical Specifications Changes DRESDEN NUCLEAR POWER STATION REVISED TS PAGES 3.3.3.1-3 3.3.3.1-4

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS

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

1. These SRs apply to each Function in Table 3.3.3.1-1, except where identified in the SR.

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the other required channel in the associated Function is OPERABLE.

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 Perform CHANNEL CALIBRATION for 92 days Function 4.b. I SR 3.3.3.1.3 ------------------- NOTE------------------

For Function 2, not required for the transmitters of the channels.

Perform CHANNEL CALIBRATION for Functions 184 days 1 and 2.

SR 3.3.3.1.4 Perform CHANNEL CALIBRATION for Functions 12 months 3 and 9.

SR 3.3.3.1.5 Perform CHANNEL CALIBRATION for Functions 24 months 2, 4.a, 5, and 6.

Dresden 2 and 3 3.3.3. 1-3 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 REOUIRED FUNCTION CHANNELS ACTION D.1

1. Reactor Vessel Pressure 2 E

2. Reactor Vessel Water Level

a. Fuel Zone (Wide Range) 2 E

b. Medium Range 2 E

3. Torus Water Level 2 E

4. Drywell Pressure

a. Wide Range 2 E

b. Narrow Range 2 E

5. Drywell Radiation Monitors 2 F

6. Penetration Flow Path PCIV Position 2 per penetration E flow path(a)(b)

7. (Deleted) I

8. (Deleted) I

9. Torus Water Temperature 2 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.

Dresden 2 and 3 3.3.3.1-4 DAmendment No. /

ATTACHMENT 3-E Typed Pages for Technical Specifications Changes LASALLE COUNTY STATION REVISED TS PAGES 3.3.3.1-3 3.3.3.14 3.8.1-1 3.8.7-1 5.5-2 DELETED TS PAGES 3.6.3.1 (ALL)

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS

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

1. These SRs apply to each Function in Table 3.3.3.1-1. I

2. When a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the other required channel in the associated Function is OPERABLE.

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 (Deleted) I SR 3.3.3.1.3 Perform CHANNEL CALIBRATION. 24 months I LaSalle 1 and 2 3.3.3.1-3 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 E

2. Reactor Vessel Water Level

a. Fuel Zone 2 E

b. Wide Range 2 E

3. Suppression Pool Water Level 2 E

4. Drywell Pressure

a. Narrow Range 2 E

b. Wide Range 2 E

5. Primary Containment Gross Gamma Radiation 2 F

6. Penetration Flow Path PCIV Position 2 per penetration E flow path(s)(b)

7. (Deleted)

I

8. (Deleted)

I

9. Suppression Pool Water Temperature 2 E (a) Not required for isolation valves whose associated penetration flow path is isolated by at least one closed and de-activated 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.

LaSalle 1 and 2 3.3.3. 1-4 Amendment No. /

3.6.3.1 3.6 CONTAINMENT SYSTEMS 3.6.3.1 (Deleted) I LaSalle 1 and 2 3.6.3.1-1 Amendment No. /

AC Sources-Operating 3.8.1 3.8 ELECTRICAL POWER SYSTEMS 3.8.1 AC Sources-Operating LCO 3.8.1 The following AC electrical power sources shall be OPERABLE:

-a. Two qualified circuits between the offsite transmission network and the onsite Class 1E AC Electric Power Distribution System;

b. Three diesel generators (DGs); and

c. The opposite unit's Division 2 DG capable of supporting the associated equipment required to be OPERABLE by LCO 3.6.4.3, "Standby Gas Treatment (SGT) System," I LCO 3.7.4, "Control Room Area Filtration (CRAF) System,"

and LCO 3.7.5, "Control Room Area Ventilation Air Conditioning (AC) System."

APPLICABILITY: MODES 1, 2, and 3.

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

1. Division 3 AC electrical power sources are not required to be OPERABLE when High Pressure Core Spray (HPCS)

System is inoperable.

2. The opposite unit's Division 2 DG in LCO 3.8.1.c is not required to be OPERABLE when the associated required equipment is inoperable.

LaSalle I and 2 3.8.1-1 Amendment No. /

Distribution Systems-Operating 3.8.7 3.8 ELECTRICAL POWER SYSTEMS 3.8.7 Distribution Systems-Operating LCO 3.8.7 The following electrical power distribution subsystems shall be OPERABLE:

a. Division 1 and Division 2 AC and 125 V DC distribution subsystems;

b. Division 3 AC and 125 V DC distribution subsystems;

c. Division 1 250 V DC distribution subsystem; and

d. The portions of the opposite unit's Division 2 AC and 125 V DC electrical power distribution subsystems capable of supporting the equipment required to be OPERABLE by LCO 3.6.4.3, "Standby Gas Treatment (SGT) I System," LCO 3.7.4, "Control Room Area Filtration (CRAF)

System," LCO 3.7.5, "Control Room Area Ventilation Air Conditioning (AC) System," and LCO 3.8.1, "AC Sources-Operating."

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or both Division 1 A.1 Restore Division 1 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months and 2 AC electrical and 2 AC electrical power distribution power distribution AND subsystems inoperable. subsystems to OPERABLE status. 16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months from discovery of failure to meet LCO 3.8.7.a (continued)

LaSalle 1 and 2 3.8.7 -1 Amendment No. /

Programs and Manuals 5.5 5.5 Programs and Manuals.

5.5.1 Offsite Dose Calculation Manual (ODCM) (continued)

Each change shall be identified by markings in the margin of the affected pages, clearly indicating the area of the page that was changed, and shall indicate the date (i.e.,

month and year) the change was implemented.

5.5.2 Primary Coolant Sources Outside Containment This program provides controls to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during a serious transient or accident to levels as low as practicable. The systems include the Low Pressure Core Spray, High Pressure Core Spray, Residual Heat Removal/Low Pressure Coolant Injection, Reactor Core Isolation Cooling, containment monitoring, Standby Gas Treatment, hydrogen recombiner and process sampling (until such time as a modification eliminates the hydrogen recombiner and PASS penetrations as potential leakage paths). The program shall include the following:

a. Preventive maintenance and periodic visual inspection requirements; and

b. Integrated leak test requirements for each system at 24 month intervals.

The provisions of SR 3.0.2 are applicable to the 24 month Frequency for performing integrated system leak test activities.

5.5.3 Deleted.

(continued)

LaSalle 1 and 2 5.5-2 Amendment No. /

ATTACHMENT 3-F Typed Pages for Technical Specifications Change PEACH BOTTOM ATOMIC POWER STATION UNIT 2 REVISED TS PAGES 3.3-25 3.3-26 PEACH BOTTOM ATOMIC POWER STATION UNIT 3 REVISED TS PAGES 3.3-25 3.3-26

PAM Instrumentation 3.3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C Table 3.3.3.1-1 for not met. the channel.

E. As required by E.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Required Action D.1 and referenced in Table 3.3.3.1-1.

F. As required by F.1 Initiate action in Immediately Required Action D.1 accordance with and referenced in Specification 5.6.6.

Table 3.3.3.1-1.

SURVEILLANCE REQUIREMENTS _

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK for each required 31 days PAM instrumentation channel.

SR 3.3.3.1.2 Deleted I

SR 3.3.3.1.3 Perform CHANNEL CALIBRATION for each 24 months required PAM instrumentation channel.

PBAPS UNIT 2 3.3 -25 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 Pressure 2 E

2. Reactor Vessel Water Level (Wide Range) 2 E

3. Reactor Vessel Water Level (Fuel Zone) 2 E

4. Suppression Chamber Water Level (Wide Range) 2 E

5. Drywell Pressure (Wide Range) 2 E

6. Drywell Pressure (Subatmospheric Range) 2 E

7. Drywell High Range Radiation 2 F

8. PCIV Position 2 per penetration flow E path (a)(b)

9. Deleted I

10. Deleted I

11. Suppression Chamber Water Temperature 2 (c) 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) Each channel requires 10 resistance temperature detectors (RTDs) to be OPERABLE with no two adjacent RTDs inoperable.

PBAPS UNIT 2 3.3 -26 Amendment No.

PAM Instrumentation 3.3.3.1 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C Table 3.3.3.1-1 for not met. the channel.

E. As required by E.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Required Action D.1 and referenced in Table 3.3.3.1-1.

F. As required by F.1 Initiate action in Immediately Required Action D.1 accordance with and referenced in Specification 5.6.6.

Table 3.3.3.1-1.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK.for each required 31 days PAM instrumentation channel.

SR 3.3.3.1.2 Deleted I

SR 3.3.3.1.3 Perform CHANNEL CALIBRATION for each 24 months required PAM instrumentation channel. I PBAPS UNIT 3 3.3 -25 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 Pressure 2 E

2. Reactor Vessel Water Level (Wide Range) 2 E

3. Reactor Vessel Water Level (Fuel Zone) 2 E

4. Suppression Chamber Water Level (Wide Range) 2 E S. Drywell Pressure (Wide Range) 2 E

6. Drywell Pressure (Subatmospheric Range) 2 E

7. Orywell High Range Radiation 2 F

8. PCIV Position 2 per penetration flow E path (a)(b)

9. Deleted I

10. Deleted

11. Suppression Chamber Water Temperature 2 (c) 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.

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

(c) Each channel requires 10 resistance temperature detectors (RTDs) to be OPERABLE with no two adjacent RTDs inoperable.

PBAPS UNIT 3 3.3 -26 PAmendment No.

ATTACHMENT 3-G Typed Pages for Technical Specifications Changes QUAD CITIES NUCLEAR POWER STATION REVISED TS PAGES 3.3.3.1-3 3.3.3.1-4

PAM Instrumentation 3.3.3.1 SURVEILLANCE REQUIREMENTS

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

When a channel is placed in an inoperable status solely for performance of I required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months provided the other required channel in the associated Function is OPERABLE.

SURVEILLANCE FREQUENCY SR 3.3.3.1.1 Perform CHANNEL CHECK. 31 days SR 3.3.3.1.2 Perform CHANNEL CALIBRATION. 24 months I

Quad Cities 1 and 2 3.3.3. 1-3 Amendment No. /

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

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

1. Reactor Vessel Pressure 2 E

2. Reactor Vessel Water Level

a. Wide Range 2 E

b. Narrow Range 2 E

3. Torus Water Level 2 E

4. Drywell Pressure

a. Wide Range 2 E

b. Narrow Range 2 E

5. Drywell Radiation Monitors 2 F

6. Penetration Flow Path PCIV Position 2 per penetration E flow patha)ob

7. Torus Water Temperature 2 E I

(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.

Quad Cities 1 and 2 3.3.3.1-4 Amendment No. /

ATTACHMENT 4-A Markup of Technical Specifications Bases Changes BRAIDWOOD STATION REVISED TS BASES PAGES B 3.3.3-11 B 3.3.3-13 B 3.3.3-14 B 3.3.3-15 B 3.3.3-16 DELETED TS BASES PAGES B 3.6.8 ALL

PAM Instrumentation B 3.3.3 BASES LCO (continued)

14. Reactor Vessel Water Level Reactor Vessel Water Level is provided for verification and long term surveillance of core cooling. It is also used for accident diagnosis and to determine reactor coolant inventory adequacy.

The Reactor Vessel Water Level Monitoring System provides a direct measurement of the liquid level above the fuel. Two channels are required OPERABLE (Train A and Train B). Each channel consists of eight sensors on a probe. For a channel to be considered OPERABLE one of the two sensors in the "head" region and three of the six sensors in the "plenum" region shall be OPERABLE. The level indicated by the OPERABLE sensors represents the amount of liquid mass that is in the reactor vessel above the core.

Operability of each sensor may be determined by reviewing the error codes displayed on the control room indicator.

15. Ilvdroj e-NeMonitor:s(&jpe~t CeD - ci Hydrogen Monitors arc provided to detcet high hydrogen

-concentrateion

,f n imme codtostaeprsn kntt r1-;

nbprah a poeta This variable is also important in verifying thc adequacy of mitigating actions.

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2, and 3. In MODE-3, the hydrogen monitoring function is not eJede) ruired sinee the hy prodction ate and the total J ,UdI V'iLW IJ VUUUb-LL VUL~V bLV JZ if UI[ 1 L L.UJLLJLU 4 IL/X IWV8VCb1 DAlLOGAl- These variables are related to the diagnosis and pre-planned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1, 2, and 3.

In MODES 4, 5, and 6, unit conditions are such that the likelihood of an event that would require PAM instrumentation is low; therefore, the PAM instrumentation is not required to be OPERABLE in these MODES.

BRAIDWOOD - UNITS 1 & 2 B 3.3.3 - 11 Revi si on 0/

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)

CA1 Condition C applies when the Required Action and associated Completion Time for Condition B are not met. This Required Action specifies the immediate initiation of actions in accordance with Specification 5.6.7, which requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability 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.

D.1 and E.1 Condition D applies to Functions with one required channel as required to be entered by Table 3.3.3-1. Required Action D.1 requires restoration of an inoperable channel within 7 days. Condition E applies to one or more Functions with two or more required inoperable channels on the same Function. Required Action E.1 requires all but one channel on the same Function be restored 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 no required channels OPERABLE 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 the channel(s) limits the risk that the PAM Function will be in a degraded condition should an accident occur.

Condition [ is modified by a Notc that cxcludes hydrogen mlnitor ehuln nlez.

BRAIDWOOD - UNITS 1 & 2 B 3.3.3 - 13 Revision I

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued) ttsS~tonF aplis hen two hydrogen monitor chann inop~lles equredAction F.1 requires rs;d~ n hyroenmniln-6anel to OPERABLE sty~ihin 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 Completio 4E is rezn l based on other core damage assessment ca available to monitor the hydrogen concentrati r evaluation re damage and to provide infor for operator decisions.

unlikel a LOCA (which would cause core damage uring this time.

6.7&l&nd-G. F1 R2-If the Required Action and associated Completion Time of Condition DcrEe er-F- is not met, 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 .

Condition G is also modified by a Note that excludes Functions 11, 12, and 14. Pequird-Action G.2 is iifie&

bya Nete that exeludes--Funet-4io 1.5 sineT thjhdrogen monitor alrc only applicable in ODES 1 U1nU L.

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

BRAIDWOOD - UNITS 1 & 2 B 3. 3. 3 - 14 Revision

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)

If the Required Action and associated Completion Time of Condition D or E is not met, Required Action JA-1? 9ecifies the immediate initiation of actions in accordance with Specification 5.6.7. This Specification requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability 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 low likelihood of unit conditions that would require information provided by this instrumentation. Conditionx-is modified by a Note that indicates that this Condition is only applicable to Functions 11, 12, and 14.

SURVEILLANCE A Note has been added to the SR Table to clarify that REQUIREMENTS SR 3.3.3.1 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 instruments located throughout the plant.

BRAIDWOOD - UNITS 1 & 2 B 3.3.3 - 15 Revision/

PAM Instrumentation B 3.3.3 BASES SURVEILLANCE REQUIREMENTS (continued)

Agreement criteria are determined 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.

As specified in the SR, a CHANNEL CHECK is only required for those channels that are normally energized.

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.

SR 3.3.3.2 A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor.

The test verifies that the channel responds to measured parameter with the necessary range and accuracy. The CHANNEL CALIBRATION may consist of an electronic calibration of the channel for range decades above 10 R/h and a one point calibration check of the detector below 10 R/h with an installed or portable gamma source. For the hydrogen monitors, 5;n a CIANINEL-r CA.,-LIBRATION isp-erformed using five gas.-

thc rA nge frAM -rE volumo pcrocnt

.1UI. V I -p Wl I. 4-I I VW I- I sL U I ; 1l n W V wV W I T hyidroegen-r(100$ N2) to >2 voume per ent, hyd. genT-iehbalee-Ye!

nitrogen.

BRAIDWOOD - UNITS 1 & 2 B 3.3.3 - 16 Revisions/

Hydrogen Recombiner B 3.6 B 3.6 NTAINMENT SYSTEMS B 3.6.8 drogen Recombiners BASES BACKGROUND he function of the hydrogen recombiners is eliminate the p tential breach of containment due to a hydrogen oxygen re tion.

Per 1 CFR 50.44, "Standards for Combus ble Gas Control System in Light-Water-Cooled Reactor (Ref. 1), and GDC 41, 'Containment Atmosphere Clea p" (Ref. 2), hydrogen recombine are required to reduce e hydrogen concentrat n inthe containment filowing a Loss Of Coolant Accident (L A) or Steam Line BrP k (SLB). The recombiners accomplish tW by recombining drogen and oxygen to form water vapor. e vapor remai incontainment, thus eliminating any ischarge to he environment. The hydrogen recombiners are m ually in' iated since flammable limits would not be reach until several days after a Design Basis Accident (DBA).

Two 100% capacity inde ndent hydrogen recombiner systems are provided and shar d etween the units. Each consists of controls located in he a iliary building, a power supply and a recombiner. ecombi tion is accomplished by heating a hydrogen air m ture to 1 50F. The resulting water vapor and discharge g es are coole prior to discharge from the recombiner. single recombin is capable of maintaining the hydrogen oncentration in c tainment below the 4.0 volume rcent (v/o) flammabi ity limit. Two I recombiner are provided to meet t requirement for redundan and independence. Each combiner is powered from a parate Engineered Safety Fea ures bus, and is provid d with a separate power panel a control panel.

The ydrogen recombiners are described inUFSAR, Se ion 6.2.5 (Ref. 3).

B 3.6.8 - 1 Revision 23

Hydrogen Recombiners B 3. .8 BASES\

APPLICABLE The hydrogen recombiners provide for the capabilit of SAFETY ANALYS controlling the bulk hydrogen concentration in co tainment to less than the lower flammable concentration 4.0 v/o following a DBA. This control would prevent a/containment wide hydrogen burn, thus ensuring the pressur and temperature assumed in the analyses are not vxceeded. The imiting DBA relative to hydrogen generatig is a LOCA.

H rogen may accumulate in containment fo owing a LOCA as a res it of:

a. metal steam reaction between e zirconium fuel rod c dding and the reactor coola

b. Radi lytic decomposition of ater in the Reactor Coola t System (RCS) and t containment sump;

c. Hydroge in the RCS at t e time of the LOCA (i.e.,

hydrogen issolved in e reactor coolant and hydrogen gas inthe ressurize vapor space); or

d. Corrosion of tal exposed to containment spray and Emergency Core C ing System solutions.

To evaluate the pot ial for hydrogen accumulation in containment follow'g LOCA, the hydrogen generation as a function of time ollowi g the initiation of the accident is calculated. Co ervative assumptions recommended by Reference 4 ar used to ma imize the amount of hydrogen calculated.

Based on t conservative assu tions used to calculate the hydrogen oncentration versus t after a LOCA, the hydroge concentration in the pr ary containment would reach .6v/o about 20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months afte the LOCA and 4.0 v/o about/4 days later if.no recombiner was functioning (Ref. 3). Initiating a hydrogen rec biner when the primary co ainment hydrogen concentration re hes 2.6 v/o will intain the hydrogen concentration in he primary ontainment below flammability limits.

/RAIDWOOD - UNITS 1 & 2 B 3.6.8 - 2 Revision 23

Hydrogen Recombiners B 3.6.8 BASES APPLICABLE FETY ANAYLSES (continued)

The hydrogen recombiners are designed such that, wi the conservatively calculated hydrogen generation rat discussed above, a single recombiner is capable limiting e peak hydrogen concentration in containment o less than 4.R v/o (Ref. 5).

The drogen recombiners satisfy Criterion of 10 CF 50.36(c)(2)(ii).

LCO Two hydro n recombiners must be OPE LE. This ensures operation o at least one hydrogen r combiner in the event of a worst c e single active fail e.

Operation with t least one hyd gen recombiner ensures that the post LOCA hy ogen concent ation can be prevented from exceeding the fla ability 1i it.

APPLICABILITY InMODES 1 and 2, two y ogen recombiners are required to control the hydrogen co centration within containment below its flammability limi o 4.0 v/o following a LOCA, assuming a worst case single ilu InMODES 3 and 4, 0th the h rogen production rate and the total hydrogen p oduced after LOCA would be less than that calculated for he DBA LOCA. A0so, because of the limited time in these ODES, the probabi ity of an accident requiring th hydrogen recombiner islow. Therefore, the hydrogen r ombiners are not requird in MODE. 3 or 4.

In MODES/5 and 6, the probability and onsequences of a LOCA are 10o due to the pressure and temper ture limitations in these ODES. Therefore, hydrogen recomb ers are not req red in these MODES.

/kAIDWOOD- UNITS 1 & 2 B 3.6.8 - 3 Revision 0

Hydrogen Recombine B 3 .8 BASES ACTIONS A.1 With one containment hydrogen recombiner inoper le, the inoperable recombiner must be restored to OPE BLE status ithin 30 days. In this condition, the rema ing OPERABLE h drogen recombiner is adequate to perfom e hydrogen co trol function. However, the overall r iability is red ed because a single failure in the ERABLE recombiner coul result in reduced hydrogen controy capability. The 30 day Completion Time is based on th availability of the other hyrogen recombiner, the small robability of a LOCA or SLB o urring (that would genera e an amount of hydrogen that excee s the flammability limi ), and the amount of time available a ter a LOCA or SLB (s uld one occur) for operator act n to prevent hydr gen accumulation from exceeding the lammability li ft.

Required Action .1 has bee modified by a Note that states the provisions of CO 3.0. are not applicable. As a result, a MODE cha e is; lIowed when one recombiner is inoperable. This al ow ce is based on the availability of the other hydrogen re mbiner, the small probability of a LOCA or SLB occurrin hat would generate an amount of hydrogen that excee s t flammability limit), and the amount of time av able fter a LOCA or SLB (should one occur) for opera r action o prevent hydrogen accumulation from exceeding re flammabi ty limit.

3RAIDWOOD - UNITS 1 & 2 B 3.6.8 - 4 Revision 0

Hydrogen Recombiner B 3. .

BASES\/

ACTIONS Iontinued)

B.1 and B.2 With two hydrogen recombiners inoperable, the bility to perform the hydrogen control function via al mate cap abilities must be verified by administra ive means within hour. The alternate hydrogen control caabilities are p ovided by the natural convection proce es, containment fa cooler operation, containment spray and the Post-LOCA Pur System. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion TIme allows a.

reaso able period of time to verify at a loss of hydrogen contro function does not exist. I addition, the alternate hydroge control system capability must be verified once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months hereafter to ensure it continued availability.

Both the i itial verification a d all subsequent verificatio may be performe as an administrative check by examining lo or other infor ation to determine the availability o the alterna hydrogen control system. It does not mean t erform t e Surveillances needed to demonstrate OPE ILITY the alternate hydrogen control system. If the a"lity o perform the hydrogen control function is maintal ed continued operation is permitted with two hydrogen r mbiners inoperable for up to 7 days.

Seven days is a rea ble time to allow two hydrogen recombiners to be ' op rable because the hydrogen control function is main med ad because of the low probability of the occurrence ok a LOCA What would generate hydrogen in the amounts capabl of exceedi the flammability limit.

C.1 If the i perable hydrogen reco iner(s) cannot be restored to OPE LE status within the re ired Completion Time or the hy ogen control function cann t be maintained, the plant ust be brought to a MODE in ich the LCO does not appl . To achieve this status, the ant must be brought to at east MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The pletion Time of 6 ours is reasonable, based on operati experience, to each MODE 3 from full power conditions an orderly manner and without challenging plant systems.

IDWOOD - UNITS 1 & 2 B 3.6.8 - 5 Revision 0

Hydrogen Recombiners B 3.6 8 BASES SURVEILLANCE SR 3.6.8.1 REQUIREMENTS Performance of a system functional test for each ydrogen ecombiner ensures the recombiners are operatio Ial and can tain and sustain the temperature necessary f r hydrogen re ombination. In particular, this SR verif s that the mim um heater sheath temperature increases o 2 1200OF in

< 90 nutes. After reaching 1200 0F, the ower is increased to max uum power for approximately 2 min es and power is verifie to be 2 38 kW.

Operating perience has shown that ese components usually pass the Su eillance when performe at the 18 month Frequency. erefore, the Freque jy was concluded to be acceptable fro a reliability st dpoint.

SR 3.6.8.2 This SR ensures the are n physical problems that could affect recombiner ope ati . Since the recombiners are mechanically passive, are not subject to mechanical failure. The only cred le failure involves loss of power, blockage of the inter 1 low, missile impact, etc.

A visual inspection is suffi ient to determine abnormal conditions (e.g., oose wirin or structural connections, deposits of fore'n material, c.) that could cause such failures. The month Frequen for this SR was developed considering t incidence of hydr en recombiners failing the SR in th past is low.

SR 3.6.8.

This S requires performance of a resist nce to ground test for eah heater phase to ensure that ther are no dete able grounds in any heater phase. T *s is acc plished by verifying that the resistanc to ground for a heater phase is 2 10,000 ohms.

he 18 month Frequency for this Surveillance was developed considering the incidence of hydrogen recombiners ailing the SR in the past is low.

IDWOOD - UNITS 1 &2 B 3.6.8 - 6 Revision 0

REFERENCES 10 CFR 50.44.

10 CFR 50, Appendix A, GDC 41.

UFSAR, Section 6.2.5.

4. Regulatory Guide 1.7, Revision 2.

5. k SAR, Chapter 15.

B 3.6.8 - 7 Revision 0

Hydrogen Recombiners B 3.6.

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B 3.6.8 - 8 Revisiob 0

ATTACHMENT 4-B Markup of Technical Specifications Bases Changes BYRON STATION REVISED TS BASES PAGES B 3.3.3-11 B 3.3.3-13 B 3.3.3-14 B 3.3.3-15 B 3.3.3-16 DELETED TS BASES PAGES B 3.6.8 ALL

PAM Instrumentation B 3.3.3 BASES LCO (continued)

14. Reactor Vessel Water Level Reactor Vessel Water Level is provided for verification and long term surveillance of core cooling. It is also used for accident diagnosis and to determine reactor coolant inventory adequacy.

The Reactor Vessel Water Level Monitoring System provides a direct measurement of the liquid level above the fuel. Two channels are required OPERABLE (Train A and Train B). Each channel consists of eight sensors on a probe. For a channel to be considered OPERABLE one of the two sensors in the "head" region and three of the six sensors in the "plenum" region shall be OPERABLE. The level indicated by the OPERABLE sensors represents the amount of liquid mass that is in the reactor vessel above the core.

Operability of each sensor may be determined by reviewing the error codes displayed on the control room indicator.

15 Udiuen Mantr Hlydrogen Monitors are provided to detect high hydrogen eonerntration onditions- that represent- t al for containment breach from a hydoge epoion.

This variable isaio IIiornt II tnhe

-adeqttaey of mfit~igating Actionne APPLICABI LITY The PAM instrumentation LCO is applicable in MODES 1, 2, and 3. In H1ODE 3, the hydrogen molnitoring function is net raststIr one th .aduetienh r'teand the total

~~~~~~heaoc lessrdcdwudb than that calculated for the-9BALOCA-. These variables are related to the diagnosis and pre-planned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1, 2, and 3.

In MODES 4, 5, and 6, unit conditions are such that the likelihood of an event that would require PAM instrumentation is low; therefore, the PAM instrumentation is not required to be OPERABLE in these MODES.

BYRON - UNITS 1 & 2 B 3.3.3 - 11 Revision x

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)

C.1 Condition C applies when the Required Action and associated Completion Time for Condition B are not met. This Required Action specifies the immediate initiation of actions in accordance with Specification 5.6.7, which requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability 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.

D.1 and E.1 Condition D applies to Functions with one required channel as required to be entered by Table 3.3.3-1. Required Action D.1 requires restoration of an inoperable channel within 7 days. Condition E applies to one or more Functions with two or more required inoperable channels on the same Function. Required Action E.1 requires all but one channel on the same Function be restored 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 no required channels OPERABLE 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 the channel(s) limits the risk that the PAM Function will be in a degraded condition should an accident occur.

Rendition [ is modified by a Note that excludes hydrogen mffonitor channAl M.

BYRON - UNITS 1 & 2 8 3.3.3 - 13 Revision/

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued) 8nit~o Faplis hen two hydrogen monito v*§es are inpeafQ?__eqirdAction F.1 require-Etrn one hydrogen monitoh nel to OPERAB atus 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 Completion i asonable based on other core damage assessment i available to monitor the hydrogen concentra for evaluationra& core damage and to provide infor on for operator decisions. -A;s, it is unlikel at a LOCA (which would cause core damag ld os tduring this time.

r FKIl andZ.2 If the Required Action and associated Completion Time of Condition DorE-or---F-is not met, 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 .

Condition G is also modified by a Note that excludes Functions 11, 12, and 14. R equired Action C.2 is modified bya Notc that exeludoe Function 15 sinee the hydrogen 1--beor- are onlly applic-ab in MO0DES 1 and 2.

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 plant systems.

BYRON - UNITS 1 & 2 B 3.3.3 - 14 Revision.,Xt

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)

If the Required Action and associated Completion Time of Condition D or E is not met, Required Actior¶.*1 specifies the immediate initiation of actions in accordance with Specification 5.6.7. This Specification requires a written report to be submitted to the NRC. This report discusses the results of the root cause evaluation of the inoperability 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 low likelihood of unit conditions that would require information provided by this instrumentation. Condition )(is modified by a Note that indicates that this Condition is only applicable to Functions 11, 12, and 14.

SURVEILLANCE A Note has been added to the SR Table to clarify that REQUIREMENTS SR 3.3.3.1 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 instruments located throughout the plant.

BYRON - UNITS 1 & 2 B 3.3.3 ---

15 Revision.Z

PAM Instrumentation B 3.3.3 BASES SURVEILLANCE REQUIREMENTS (continued)

Agreement criteria are determined 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.

As specified in the SR, a CHANNEL CHECK is only required for those channels that are normally energized.

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.

SR 3.3.3.2 A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor.

The test verifies that the channel responds to measured parameter with the necessary range and accuracy. The CHANNEL CALIBRATION may consist of an electronic calibration of the channel for range decades above 10 R/h and a one point calibration check of the detector below 10 R/h with an installed or portable gamma source. For the hydrogen monitors, a CHANNEL CALIBRATION is pcrformcd using five gas zamplc which cover the range from cro vol um percent

-hydrogen (10% N2) to > 20 volume percent hydrogen, balanee

-nitrogen.-

BYRON - UNITS 1 & 2 B 3.3.3 - 16 Revisiony

Hydrogen Recombiners 3.6.8 36 CONTAINMENT SYSTEMS 3.6.8 drogen Recombiners LCO 3.6.8 ecombiners shall be OPERAB LE.

Two hydrogen ru APPLICABILITY: ODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One hydrogen A.1 -------- NOTE-recombiner inoperable. LCO 3.0.4 is ot applicable.

Restore ydrogen 30 days recomb er to OPERA E status.

B. Two hydrogen B.1 Vrfy by 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months recombiners dmi strative means inoperable. that t e hydrogen AND control unction is maintain Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.2 Restore one hydro n 7 days recombiner to OPERABLE status.

C. Required Acti and C.1 Be in MODE 3. hours associated C mpletion Time not DOOD - UNITS 1 & 2 3.6.8 - 1 Amendment 98

Hydrogen Recombiners 3.6.8 SUR E LANCE REQUIREMENTS SURVEILLANCE FREQUYCY SR 3.6.8. Perform a system functional test for each 18 mots hydrogen recombiner.

SR 3.6.8.2 + ually examine each hydrogen recombiner moths

- encosure and verify there is no evidence of normal conditions.

SR 3.6.8.3 Perform resistance to ground test for 18 months each hea r phase.

IDWOOD - UNITS 1 & 2 3.6.8 - 2 Amendment 98

Hydrogen Recombiner B 3.6 BASES APPLICABLE FETY ANAYLSES (continued)

The hydrogen recombiners are designed such that, ith the conservatively calculated hydrogen generation raes discussed above, a single recombiner is-capabl of limiting he peak hydrogen concentration incontainmen to less than 4 0 v/o (Ref. 5).

The drogen recombiners satisfy Criteria 3 of 10 C 50.36(c)(2)(ii).

LCO Two hydro en recombiners must be OP BLE. This ensures operation at least one hydrogen ecombiner inthe event of a worst se single active fa ure.

Operation wit at least one hy ogen recombiner ensures that the post LOCA hdrogen conce ration can be prevented from exceeding the fi bility mit.

APPLICABILITY InMODES 1 and 2,tw h ro en recombiners are required to control the hydrogen ncen ration within containment below its flamnability lim f 4.0 v/o following a LOCA, assuming a worst case single ail re.

InMODES 3 and 4 both the ydro en production rate and the total hydrogen oduced afte a OCA would be less than that calculated for the DBA LOCA. iso, because of the limited time inthes MODES, the proba lity of an accident requiringt hydrogen recombin s islow. Therefore, the hydrogenr combiners are not requ ed inMODE 3 or 4.

InMODE 5 and 6,the probability a consequences of a LOCA are 1 , due to the pressure and te rature limitations in thes MODES. Therefore, hydrogen reco biners are not re ired in these MODES.

- UNITS 1 & 2 B 3.6.8 - 3 Revision

Hydrogen Recombine s

\ B83. <.8 BASES ACTIONS Ad With one containment hydrogen recombiner imoper e,the inoperable recombiner must be restored to OPE LEstatus within 30 days. Inthis condition, the remal ng OPERABLE ydrogen recombiner isadequate to perform t e hydrogen c ntrol function. However, the overall rel ability is re ced because a single failure in the OP RABLE recombiner cou result in reduced hydrogen control apability. The 30 da Completion Time is based on the vailability of the other drogen recombiner, the small obability of a LOCA or SLB curring (that would generatean amount of hydrogen that exce ds the flammability limit , and the amount of time available fter a LOCA or SLB (sho d one occur) for operator ac *on to prevent hydrogn accumulation from exceeding the flammability limi Required Action .1has been dified by a Note that states the provisions o LCO 3.0.4 re not applicable. As a result, a MODE cha e isa owed when one recombiner is inoperable. This a owan e isbased on the availability of the other hydrogen re o iner, the small probability of a LOCA or SLB occurring hat would generate an amount of hydrogen that exceeds flammability limit), and the amount of time avail le fter a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding th flanmabi ty limit.

- UNITS 1 & 2 B 3.6.8 - 4 Revision 0

Hydrogen Recombir rs B .6.8 BASES-/

ACTIONS continued)

B.1 and B.2 With two hydrogen recombiners inoperable, th ability to perform the hydrogen control function via a ternate capabilities must be verified by administr tive means within hour. The alternate hydrogen control pabilities are ovided by the natural convection proc sses, containment fa cooler operation, containment spra, and the Post-LOCA PurI e S stem. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completionime allows a reas able period of time to verify hat a loss of hydrogen contro function does not exist. n addition, the alternate hydroge control system capabili must be verified once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months hereafter to ensure i continued availability.

Both the initial verification d all subsequent verificatio s may be perfor as an administrative check by examining lo or other inf tion to determine the availability the altern e hydrogen control system. It does not mean t erform e Survei1lances needed to demonstrate OPE ILITY f the alternate hydrogen control system. If the a ilit to perform the hydrogen control function is maintai , continued operation is permitted with two hydrogen r mbiners inoperable for up to 7 days.

Seven days is a re onble time to allow two hydrogen recombiners to be nope able because the hydrogen control function is main ained a because of the low probability of the occurrence f a LOCA at would generate hydrogen in the amounts capab of exceedi the flammability limit.

If the i erable hydrogen reco iner(s) cannot be restored to OPERLE status within the req ired Completion Time or the hy rogen control function cann be maintained, the plan must be brought to a MODE in ich the LCO does not app . To achieve this status, the p nt must be brought to at east MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The Coletion Time of hours is reasonable based on operatin experience, to each MODE 3 from full power conditions l an orderly manner and without challenging plant systems.

RON - UNITS 1 & 2 B 3.6.8 - 5 Revision\

Hydrogen Recombiners B 3.6.8 BASE SURVEIL E SR 3.6.8.1 REQUIREME Performance of a system functional test for each hydr gen recombiner ensures the recombiners are operational d can attain and sustain the temperature necessary for h drogen recombination. In particular, this SR verifies at the inimum heater sheath temperature increases to !12O0PF in

.90 minutes. After reaching 1200 0F, the power is increased tmaximum power for approximately 2 minutes nd power is verfied to be 2 38 kW.

Operatng experience has shown that thes components usually pass th Surveillance when performed at he 18month requenc Therefore, the Frequency s concluded to be acceptable rom a reliability standp nt.

SR 3.6.8.2 This SR ensures here are no p ical problems that could affect recombiner operation. ince the recombiners are mechanically passie, they age not subject to mechanical failure. The only edibi failure involves loss of power, blockage of the inter 1 ow, missile impact, etc.

A visual inspection is fficient to determine abnormal conditions (e.g., loo1 e wring or structural connections, deposits of foreign teria , etc.) that could cause such failures. The 18 nth Freq ncy for this SR was developed considering the I cidence of drogen recombiners failing the SR in the p t is low.

SR 3.6.8.3 This SR re ires performance of a resistance to ground test for each eater phase to ensure that t ere are no detectabe grounds in any heater phase. This is accomp ished by verifying that the resis ance to ground for any ater phase is Ž 10,000 ohms.

T 18 month Frequency for this Surveillance as developed nsidering the incidence of hydrogen recombin s failing he SR in the past is low.

76N - UNITS 1 & 2 B 3.6.8 - 6 Revision O

Hydrogen REFERENCES 10 CFR 50.44.

10 CFR 50, Appendix A, GDC 41.

UFSAR, Section 6.2.5.

4. Regulatory Guide 1.7, Revision 2.

5. MQFSAR, Chapter 15.

- UNITS 1 & 2 B 3.6.8 - 7 Revision 0

Hydrogen This page intenoonal \left blank.

- UNITS 1 & 2 B 3.6.8 - 8 Revision 0

ATTACHMENT 4-C Markup of Technical Specifications Bases Changes CLINTON POWER STATION REVISED TS BASES PAGES B 3.3-53 B 3.3-54 B 3.3-59 DELETED TS BASES PAGES B 3.6.66 B 3.6.67 B 3.6.68 B 3.6.69 B 3.6.70 B 3.6.71

PAM Instrumentation B 3.3.3.1 BASES LCO 6. Drywell Area Radiation (continued)

Drywell area radiation (high range) 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. Two high range radiation detectors are provided to monitor the drywell area gross gamma radiation levels. These detectors monitor the range 1 to 10E7 R/hr and provide inputs to monitors in the main control room.

The monitors are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

7. Primary Containment Isolation Valve (PCIV) Position PCIV position is provided for verification of containment integrity. In the case of PCIV position, the important information is the status of the containment penetration.

The LCO requires one channel of valve position indication in the control room to be OPERABLE for each automatic PCIV in a containment penetration flow path; i.e., two total channels of PCIV position indication for a penetration flow path with two automatic valves. For containment penetrations with only one automatic PCIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient to verify redundantly the isolation status of each isolable penetration via indicated status of the automatic valve and, as applicable, prior knowledge of passive valve or system boundary status.

If a penetration is isolated by at least one closed and de-activated automatic valve, closed manual valve, blind flange, or check valve with flow through the valve secured, 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 is not required to be OPERABLE.

8. Drywell and Containment Hydrogen and Oxygen Analyzer (pelt 9) d containment hydrogen and oxygen anal z Category I I rvded doen to or oxygen concentration coD~s r-8 nresent a potential for conta i s~~ggl This varibesa

-verrrE7l(h adequacy of mitigating actions.

(continued)

CLINTON B 3.3-53 Revision No. /

PAM Instrumentation B 3.3.3.1 BASES LCO . ^Drywell and Containment Hydrogen and Oxygen Analyzer' (cont' d)

Two gas chr ograph hydrogen and oxygen a z ers are provided. Each hese monitors autom cally takes samples from five 10 ions in the well and containment.

Gas chromatograph techni s are en utilized to separate the gaseous sample mixture its individual components.

A thermal conductivity c ana s each component to determine its concen tion with re ct to total sample volume. The res s of the analysis are dicated and printed out he main control room. The icators provide t primary indication used by the oper r during an ac ent. Therefore, the PAM Specification deal s if ically with this portion of the instrument chann

9. Primary Containment Pressure Primary containment pressure is a Category I variable provided to verify RCS and containment integrity and to verify the effectiveness of ECCS actions taken to prevent containment breach. Four wide range primary containment pressure signals are transmitted from separate pressure transmitters and are continuously recorded and displayed on four control room recorders. Two of these instruments monitor containment pressure from -5 psig to 10 psig (low range). The remaining two,instruments monitor containment pressure from 5 psig to 45 psig (high range). These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.

10. Suppression Pool Water Bulk Average Temperature Suppression pool water bulk average 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 instrumentation allows operators to detect trends in suppression pool water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool. Eight temperature sensors are arranged in two channels (i.e., divisions), located such that there is one sensor from each channel (division) within each quadrant of the suppression pool. These instruments provide the capability to monitor suppression pool water temperature (continued)

CLINTON B 3.3-54 Revision No.

PAM Instrumentation B 3.3.3.1 BASES 5j 3.3.-3. 1 ( oejeT~k&)

SURVEILLANCE SR 32.3.2.1. arSR 3.3.3.1.3 REQUIREMENTS (continued) For all Functions except-the-dweI4 hydregen and-eygen ealyzee~ro, a CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop including the sensor. The test verifies that the channel responds to the measured parameter with the necessary range and accuracy. The Frequency is based on operating experience and consistency with the typical industry refueling cycles.

The CHANNEL CALIBRATION of the Primary Containment and Drywell Area Radiation Functions consists of an electronic calibration of the channel, not including the detector, for range decades above 10 R per hour and a one point calibration check of the detector below 10 R per hour with an installed or portable gamma source.

-Prthe~vdrogen and oxygen analyzers, a CHANNEL CAT.

is performed his c performed using an integral gas su ai oxygen, and inert c oncentrations consistent wi

=iml-5-turer's recommendations.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," Revision 3, May 1983.

2. SSER 5, Section 7.5.3.1.

3. USAR, Table 7.1-13.

4. USAR Section 7.5.1.4.2.4.

CLINTON B 3.3-59 Revision No.

Primary Containment Hydrogen Recombiners B 3.6.3.1 B 3.6 ONTAINMENT SYSTEMS B 3.6.3.1 Primary Containment Hydrogen Recombiners BASES BACKGRIOUND The primary containment hydrogen recombiner liminates the otential breach of primary containment du to a hydrogen gen reaction and is part of combustib gas control reired by 10 CFR 50.44, "Standards fo Combustible Gas Con rol in Light-Water-Cooled Reactors' (Ref. 1), and GDC 1, "Containment Atmosphere Clea p" (Ref. 2). The prima containment hydrogen recomb er is required to reduce he hydrogen concentration In the primary containment followi a loss of coolant acci nt (LOCA). The primary containme t hydrogen recombiner ccomplishes this by recombinin hydrogen and oxyge to form water vapor. The vapor is re urned to the pri ry containment, thus eliminating y discharge t the environment. The primary containment hdrogen reco iner is manually initiated, since flammability iiits woul 'not be reached until several days after a Design B sis Ac dent (DBA).

Two 100% capacity pendent primary containment hydrogen recombiner subsyste are provided. Each consists of controls located i t e control room, a power supply, an enclosed blower semb y, a heater section, a reaction section, and a oler s ction located in the control building, and ssociated iping, instruments, and valves.

Recombinatio is accompli ed by heating a hydrogen air mixture to 1150 0F. The sulting water vapor and discharge ases are cooled p ior to being discharged from the unit nd returned to the ontainment. Air flows through the'uni at 70 cfm, with a blo er in the unit providing the motive force. A single recombi r, in conjunction with the Cont nment Drywell Hydrogen Mixi g System, is capable of mai aining the hydrogen concentra ion in the drywell and pr ry containment below the 4.0 volume percent (v/o) ammability limit. Two recombiners are provided to meet he requirement for redundancy and in pendence. Each recombiner and associated containment 1nolation valves are powered from a separate Engineered Safet Feature bus.

Plant procedures direct that the hydrogen oncentration in primary containment be monitored following DBA and that the primary containment hydrogen recombiner manually (continued)

CLINTON B 3.6-66 Revision No. 0

Primary Containment Hydrogen Recombiners B 3.6.3.1

ES BACKX UD activated to prevent the primary containment atmosphere /Om (conNnUed)' reaching a bulk hydrogen concentration of 4.0 V/0. /

APPLICABLE The primary containment hydrogen recombiner provid the SAFETY ANL ES capability of controlling the bulk hydrogen conceh ration in primary containment to less than the lower fla le concentration of 4.0 v/o following a DBA. This control would prevent a primary containment wide hydr en burn, thus ensuring that pressure and temperature condi ons assumed in e analysis are not exceeded. The limitin DBA relative to hy rogen generation is a LOCA.

Hydr en may accumulate in primary cont nment following a LOCA a a result of:

a. A tal steam reaction between the zirconium fuel rod cla ing and the reactor cool nt; or

b. Radiol ic decomposition o water in the Reactor Coolant stem.

To evaluate the tential for hydrogen accumulation in primary containmen followi a LOCA, the hydrogen generation as a fun ion o time following the initiation of the accident is calc ate . Assumptions recommended by Reference 3 are used t ximize the amount of hydrogen calculated.

The calculation conf ms t t when the mitigating systems are actuated in acc dance th plant procedures, the peak hydrogen concentra ion in the rimary containment remains

< 4 v/o (Ref. 4).

The primary co ainment hydrogen ecombiners satisfy Criterion 3 o the NRC Policy Stat nt.

LCO Two prima containment hydrogen reco ners must be OPERABLE This ensures operation of at east one primary contain ent hydrogen recombiner in the evet of a worst case single active failure.

Ope tion with at least one primary containme hydrogen re mbiner subsystem ensures that the post LOCA hydrogen tration can be prevented from exceeding t P mmability limit.\

C NO B 3.6-67 Revision No. 0

Primary Containment Hydrogen Recombiners B 3.. 3.

A S(continued)

APPLI LITY In MODES 1 and 2, the two primary containment hydroge recombiners are required to control the hydrogen concentration within primary containment below its flammability limit of 4.0 v/o following a LOCA, a uming a worst case single failure.

In MODE 3, both the hydrogen production rate d the total hydrogen production after a LOCA would be le than that alculated for the DBA LOCA. Also, because of the limited t e in this MODE, the probability of an cident requiring the primary containment hydrogen recombi r is low.

Ther fore, the primary containment hydr gen recombiner is not r ired in MODE 3.

In MODESpiand 5, the probability a consequences of a LOCA are low d to the pressure and te erature limitations in these MODE Thefrem re, the pri rcontainment hydrogen recombiner inot required in t ese MODES.

ACTIONS A.1\/

With one primar ctain n hyrogen recombiner inoperable, the inoperable primy Cotiment hydrogen recombiner must be restored to OPERABgsau within 30 days. In this Condition, the remaile OPERABLE primary containment hydrogen recombiner s a equate to perform the hydrogen control function. oweve the overall reliability is reduced because a single fa lure in the OPERABLE recombiner could result in educed hydr en control capability. The 30 day Complet n Time is bas on the low probability of the occurrenc of a LOCA that uld generate hydrogen in amounts capale of exceeding the flammability limit, the amount of me available after th event for operator action to preven hydrogen accumulation exeeding this limit, and the low robability of failure of th OPERABLE primary contai ent hydrogen recombiner.

Req red Action A.1 has been modified by a Note stating that th provisions of LCO 3.0.4 are not appli ble. As a r sult, a MODE change is allowed when one combiner is noperable. This allowance is provided beca e of the low probability of the occurrence of a LOCA that uld generate hydrogen in amounts capable of exceeding the flammability limit, the low probability of the failure of the PERABLE (c ntinued)

CLINTON B 3.6-68 Revision No. 0

Primary Containment Hydrogen Recombiners B 3.6.3.

BASES ACTIONS A.l (continued) recombiner, and the amount of time available after postulated LOCA for operator action to prevent ex eding the flammability limit.

.1 and B.2 Wi two primary containment hydrogen reco iners ino rable, the ability to perform the hy ogen control funct on via alternate capabilities must/e verified by admini trative means within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Th alternate hydrogen control capabilities are provided by o e division of the hydrogen Igniters. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Compl ion Time allows a reasonable period of time to verify hat a loss of hydrogen control fun tion does not exist. e verification may be performed as n administrative chick by examining logs or other informa on to determine e availability of the alternate hydro en control sys m. It does not mean to perform the Surv illances neeed to demonstrate OPERABILITY of the alternate drogen co trol system. If the ability to perform the hydrog n contro function is maintained, continued operation "isper itted with two hydrogen recombiners inoperable f up to 7 days. Seven days is a reasonable time to allo two hydrogen recombiners to be inoperable because'the drogen control function is maintained and becaus o the low probability of the occurrence of a LO that ould generate hydrogen in the amounts capable of ceedi the flammability limit.

C.1 If any Requi d Action and requir Completion Time cannot be met, the lant must be brought t a MODE in which the LCO does not apply. To achieve this 'sta us, the plant must be brought t at least MODE 3 within 12 k)urs. The allowed Complet n Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasona e, based on operat g experience, to reach MODE 3 fr m full power condi *ons in an orderly manner and witho t challenging plan systems.

(continued)

LINTON B 3.6-69 Revision No. 0

Primary Containment Hydrogen Recombiners B 3.6.3.

BASES \(continued)

SURVEILL E SR 3.6.3.1.1 REQUIREMEN Performance of a system functional test for each imary containment hydrogen recombiner ensures that the recombiners are OPERABLE and can attain and sustain the te erature necessary for hydrogen recombination. In par cular, this SR requires verification that the reaction c amber emperature increases to 2115 0 OF in 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and that the r ction chamber is maintained 2 11770 F aid

12230 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . These verifications are requ ed to check the capa ility of the recombiner to proper y function.

Operati g experience has shown that hese components usually pass the Surveillance when perform d at the 18 month Frequency Therefore, the Freque cy was concluded to be acceptable rom a reliability s ndpoint.

With regard reaction chamb r temperature values obtained pursuant to ths SR, as reac from plant indication instrumentation the speci 4ed limit is considered to be a nominal value an therefo e does not require compensation for instrument in cati uncertainties (Ref. 5).

SR 3.6.3.1.2 This SR ensures t at th e are no physical problems that could affect pr ry con inment hydrogen recombiner operation. Si e the reco iners are mechanically passive, except for th blower asse lies, they are subject to only minimal mec nical failure. The only credible failures involve 10 of power, blocka of the internal flow path, missile i act, etc. A visual nspection is sufficient to determi abnormal conditions th t could cause such failur Oper ting experience has shown that hese components usually pa the Surveillance when performed t the 18 month F equency. Therefore, the Frequency s concluded to be cceptable from a reliability standpoin (continued)

CLINTON B 3.6-70 Revision No. 4-6

Primary Containment Hydrogen Recombiner B 3.6 .1 BASE (continued)

SURVEIL CE SR 3.6.3.1.3 REQUIREME TS This SR requires performance of a resistance to ound test of each heater phase to ensure that there are n detectable grounds in any heater phase. This is accompi hed by verifying that the resistance to ground for y heater phase is 2 10,000 ohms when this SR is performed ithin 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months following the performance of SR 3.6.3.1.1 o erating experience has shown that the e components usually pa the Surveillance when performed the 18 month Fre ency. Therefore, the Frequency as concluded to be accep ble from a reliability stand oint.

with re rd to heater resistance alues obtained pursuant to this SR, s read from plant ind. ation instrumentation, the specified imit is considered )*o be a nominal value and therefore dyes not require compensation for instrument indication u certainties (Ref. 5).

REFERENCES 1. 10 CFR 50.44.

2. 10 CFR 50, A e dix A, GDC 41.

3. Regulatory Guide .7.

4. USAR, S tion 6.2.5.

I 5. Calcu ation IP-0-0076.

CLINTON B 3.6-71 Revision No. 4-6

ATTACHMENT 4-D Markup of Technical Specifications Bases Changes DRESDEN NUCLEAR POWER STATION REVISED TS BASES PAGES B 3.3.3.1-6 B 3.3.3.1-1 1 B 3.3.3.1-12

PAM Instrumentation B 3.3.3.1 BASES LCO 6. Penetration Flow Path Primary Containment Isolation Valve (PCIV) Position (continued) 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. Each penetration is treated separately and each penetration flow path is considered a separate function. Therefore, separate Condition entry is allowed for each inoperable penetration flow path.

The indication for each PCIV is provided at the valve controls in the control room. Each indication 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.

oxS8. onrvwell Hndronen and Oxchen Concentdb two indpe and'lDnitors a Drywell hdogen and oxygen analyzers and insrmnare Categons o two iuments provided to detect syste. ogen or oxygen concanyr conditions that repae o detential en for containment br'ah This varalns also important in verifying tce adeqtion in mitigange oftions. Hydrogen and oxygen concentration g ofh 0 to by two independent analyzers and are monire i the control room. The drywell hydrogen and oxz PAM instrumentation consists of two indepeW'n gsa'yzrystems. Each gas analyzer system con ts of a hydo alyzer and an oxygen analyzer. 'Te analyzers ar aa4eof determining hydrogen conc nration in the range of 0% fl<0% and oxygen conceMntrat' fn in the range of 0% to 10%. Each' as analyzer system+s be capable of sampling the dry ell. re are tw~o,2dependent recorders in the control room to dis iy the ults; \

/ (continued)

Dresden 2 and 3 B 3.3.3.1-6 Revision X

PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.1 REQUIREMENTS (continued) Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against 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 instrument channels could be an indication of excessive instrument drift in one of the channels or 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 plant instruments located throughout the plant.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including 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.

The Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the channels required by the LCO.

SR 3.3.3.1.2. SR 3.3.3.1.3. SR 3.3.3.1.4. and SR 3.3.3.1.5 A CHANNEL CALIBRATION is performed every 92 days for Function/ 4.b, 7, and 8, every 184 days for Functions 1 and 2 (recorder only), every 12 months for Functions 3 and 9, and every 24 months for Functions 2, 4.b, 5, and 6. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies the channel responds to measured parameter with the necessary range and accuracy. For Function 5, the CHANNEL CALIBRATION shall (continued)

Dresden 2 and 3 B 3.3.3.1-11 Revision'R,

PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.2. SR 3.3.3.1.3. SR 3.3.3.1.4. and REQUIREMENTS SR 3.3.3.1.5 (continued) consist of an electronic calibration of the channel, excluding the detector, for range decades > 10 R/hour and a one point calibration check of the detector with an installed or portable gamma source for the range decade

< 10 R/hour. For Function 6, the CHANNEL CALIBRATION shall consist of verifying that the position indication conforms to actual valve position.

The Note to SR 3.3.3.1.3 states that for Function 2, this SR is not required for the transmitters of these channels.

This allowance is consistent with the plant specific setpoint methodology. This portion of the Function 2 channels must be calibrated in accordance with SR 3.3.3.1.5.

The Frequency of 92 days for Function/ 4.b,-7-~-and 8, 184 days for Functions 1 and 2 (recorder only), and 12 months for Functions 3 and 9, for CHANNEL CALIBRATION is based on operating experience.

The 24 month Frequency for CHANNEL CALIBRATION of Functions 2, 4.a, 5, and 6 is based on operating experience and consistency with the refueling cycles.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident,"

Revision 2, December 1980.

2. NRC letter, D.R. Muller (NRC) to H.E. Bliss (Commonwealth Edison Company), "Emergency Response Capability - Conformance to Regulatory Guide 1.97 Revision 2, Dresden Unit Nos. 2 and 3," September 1, 1988.

Dresden 2 and 3 B 3.3.3.1-12 Revision51-1

ATTACHMENT 4-E Markup of Technical Specifications Bases Changes LASALLE COUNTY STATION REVISED TS BASES PAGES B 3.3.3.1-6 B 3.3.3.1-11 B 3.6.3.2-1 B 3.6.3.2-2 B 3.7.2-4 B 3.8.1-1 B 3.8.1-4 B 3.8.1-7 B 3.8.7-1 B 3.8.7-3 DELETED TS BASES PAGES B 3.6.3.1 (ALL)

PAM Instrumentation B 3.3.3.1 BASES LCO 6. Penetration Flow Path Primary Containment Isolation Valve (PCIV) Position (continued)

The indication for each PCIV is provided in the control room. Indicator lights illuminate to indicate PCIV position. Therefore, the PAM Specification deals specifically with this portion of the instrumentation channel.

_ 8.D~vv;L-1 Hvdroaen, cd xv~eiei Goefteetration Aal Drywe hydrogen and oxygen concentration analyz s are Category instruments provided to detect hig ydrogen or oxygen conc ration conditions that repres t a potential for containment reach. Additionally, h rogen concentration is a pe A variable. is variable is also important in verifyin he adequacy f mitigating actions.

High hydrogen and oxyge n rations are each measured by two independent analyzers. ol ing receipt of a LOCA signal, the analyzers ar initiate nd continuously record hydrogen and oxygen c centration on t recorders in the control room. The alyzers are designed operate under accident conditi s. The available 0% to 10 ange for the hydrogen analy Oers and 0% to 20% range for the o en analyzers s isfy the intent of Regulatory Guide 1.

These re rders are the primary indication used by the opera during an accident. Therefore, the PAM \

Spe fication deals specifically with this portion of the strument channel.

9. Suppression Pool Water Temperature Suppression pool water temperature is a Type A and Category I 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 instrumentation allows operators to detect trends in suppression pool water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool. There are 14 total thermocouple instrument wells in the suppression pool. Each thermocouple (continued)

LaSalle 1 and 2 B 3.3.3.1-6 Revision 0

PAM Instrumentation PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.1 (continued)

REQUIREMENTS Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including 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.

The Frequency of 31 days is based upon plant operating experience with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the channels required by the LCO.

5$- 3.3-3.1.22(-14=)(D1 SR 3.3.3.1.. and SR 3.3.3.1.3 A CHANNEL CALIBRATION is performed every 92 days for F et -ien-s-- a-nd 8a-e- every 24 months..f-or all ot-her fURtA440N. For Function 6, the CHANNEL CALIBRATION shall consist of verifying that the position indication conforms to the actual valve position. CHANNEL CALIBRATION is a complete check of the instrument loop including the sensor.

The test verifies that the channel responds to the measured parameter with the necessary range and accuracy. -The-92 day Frequency for CHANNEL CALBRATION _f rFuneti4no 7 and S :_

bascd on operating cxpcricncc-. The 24 month Frequency for CHANNEL CALIBRATION of all other PAM Instrumentation of Table 3.3.3.1-1 is based on operating experience and consistency with the refueling cycles.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," Revision 2, December 1980.

2. NRC Safety Evaluation Report, "Commonwealth Edison Company, LaSalle County Station, Unit Nos. 1 and 2, Conformance to Regulatory Guide 1.97," dated August 20, 1987.

LaSalle 1 and 2 B 3.3.3.1-11 Revision 0

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 The primary containment is 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 inerted, 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 primary containment and maintain exygen

- 4.0 vc weorlks together w.ith the Hydrogen Recombiner System

-(LCO 3.6.3.1, "Primary Containment Hydrogen Recembincr") to-provide redundant and diieroc method: to mitigate events that produce hydrogen. For examplcAn 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. Long terfm generation of both hydrogen and oxygen f-rom radiolytic decomposition of wattr may eventually result iPn a combustible mixture irn primar-y containment, except that the hydrogen r^ e9ombire^s remee hydrogen and exygen gase:

ficstei- the they ean be produced from radiolysis and again no combustion can occur. This LCO ensures that oxygen concentration does not exceed 4.0 v/o during operation in the applicable conditions.

APPLICABLE The Reference 1 calculations assume that the primary SAFETY ANALYSES 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.

-Oxyger, whieh ia subsequnctly generated by radielytie-cdeeompozition of water, is recombined by the hydrogen receombiers (LCO 3.6.3.1) more rapidly than it is produced.

Primary containment oxygen concentration satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

(continued)

LaSalle 1 and 2 B 3.6.3.2-1 Revi si on X

Oxygen Concentration

Primary Containment Primary Containment Oxygen Concentration B 3.6.3.2 BASES (continued)

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.

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 AA1 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 4.0 A v/o because ef the av aihbility of ethoe hydregeR mitigating systems (e.g., hydrogen recombineps) and the low probability and long duration of an event that would generate significant amounts of hydrogen occurring during this period.

(continued)

LaSalle 1 and 2 B 3.6.3.2-2 Revi si onJK

yste DGCW DGCW System B 3.7.2 BASES ACTIONS A1 (continued) also requires entering into the Applicable Conditions and Required Actions for LCO 3.4.9, "RHR Shutdown Cooling System

-Hot Shutdown," LCO 3.5.1, "ECCS-Operating," LCO 3.5.3, "RCIC System," LCO 3.6.2.3, "RHR Suppression Pool Cooling,"

LCO 3.6.2.4, "RHR Suppression Pool Spray," LGO- 3.6.3.+,

"PrimfryaContainment Hydrogen Rccombincrs," and LCO 3.8.1, "AC Sources-Operating," as appropriate.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in each DGCW subsystem flow path provides assurance that the proper flow paths will exist for DGCW subsystem operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve is also allowed to be in the nonaccident position, and yet be considered in the correct position provided it can be automatically realigned to its accident position, within the required time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

SR 3.7.2.2 This SR ensures that each DGCW subsystem pump will automatically start to provide required cooling to the associated DG, LPCS pump motor cooling coils, and ECCS cubicle area cooling coils, as applicable, when the associated DG starts and the respective bus is energized.

For the Division 1 DGCW subsystem, this SR also ensures the DGCW pump automatically starts on receipt of a start signal for the unit LPCS pump. These starts may be performed using actual or simulated initiation signals.

(continued)

LaSalle 1 and 2 B 3.7.2-4 Revi si on/

AC Sources-Operating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources-Operating BASES BACKGROUND The unit Class lE AC Electrical Power Distribution System AC sources consist of the offsite power sources and the onsite standby power sources (diesel generators (DGs)). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The Class lE AC distribution system supplies electrical power to three divisional load groups, Divisions 1, 2, and 3, with each division powered by an independent Class 1E 4.16 kV emergency bus (refer to LCO 3.8.7, "Distribution Systems-Operating"). The Division 2 emergency bus associated with each unit is shared by each unit since some systems are common to both units. The opposite unit Division 2 emergency bus supports equipment required to be OPERABLE by 6GO .6.3.1, "Primary Containment Hydrogen Receembiners," LCO 3.6.4.3, "Standby Gas Treatment (SGT)

System," LCO 3.7.4, "Control Room Area Filtration (CRAF)

System," and LCO 3.7.5, "Control Room Area Ventilation Air Conditioning (AC) System." Division 1 and 2 emergency buses have access to two offsite power supplies (one normal and one alternate). The alternate offsite power source is normally supplied via the opposite unit system auxiliary transformer (SAT) and the opposite unit circuit *path. The alternate offsite circuit path includes the associated opposite unit's 4.16 kV emergency bus, unit tie breakers, and associated interconnecting bus to the given unit's 4.16 kV emergency bus. Division 3 load group has access to one offsite power supply (respective unit's SAT). Division 2 and 3 emergency buses on each unit have a dedicated onsite DG. The Division 1 emergency bus of both units share a common DG. The ESF systems of any two of the three divisions provide for the minimum safety functions necessary to shut down the unit and maintain it in a safe shutdown condition.

Offsite power is supplied to the switchyard from the transmission network. From the switchyard two electrically (continued)

LaSalle 1 and 2 B 3.8.1-1 Revision Y

AC Sources-Operating B 3.8.1 BASES APPLICABLE are designed to provide sufficient capacity, capability, SAFETY ANALYSES redundancy, and reliability to ensure the availability of (continued) necessary power to ESF systems so that the fuel, Reactor Coolant-System (RCS), and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.5, Emergency Core Cooling System (ECCS) and Reactor Core Isolation Cooling (RCIC) System; and Section 3.6, Containment Systems.

The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining the onsite or offsite AC sources OPERABLE during accident conditions in the event of:

a. An assumed loss of all offsite power or all onsite AC power; and

b. A worst case single failure.

AC sources satisfy the requirements of Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO Two qualified circuits (normal and alternate) between the offsite transmission network and the onsite Class 1E Distribution System (i.e., the unit Division 1, 2, and 3 4.16 kV emergency buses and the opposite unit Division 2 4.16 kV emergency bus), three separate and independent unit DGs, and the opposite unit's DG capable of supporting the opposite unit Division 2 onsite Class 1E AC electrical power distribution subsystem to power the equipment required to be OPERABLE by LCO 3.t.e.1, LCO 3.6.4.3, LCO 3.7.4, and LCO 3.7.5 ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA. A specific LCO requirement for a qualified circuit to provide power to the opposite unit Division 2 4.16 kV emergency bus is not provided since the alternate qualified circuit to the units Division 2 4.16 kV emergency bus encompasses the circuit path to the opposite unit Division 2 4.16 kV emergency bus.

Qualified offsite circuits are those that are described in the UFSAR and are part of the licensing basis for the unit.

(continued)

LaSalle 1 and 2 B 3.8.1-4 Revi si onAr,

AC Sources-Operating B 3.8.1 BASES APPLICABILITY allowed by this Note, the Division 3 AC sources-cannot be (continued) considered as a support system to the Division 3 AC distribution subsystem. Thus, as required by LCO 3.0.2, the Distribution System-Operating ACTIONS for the inoperable Division 3 AC electrical power distribution subsystem must be entered.

Note 2 has been added taking exception to the Applicability requirements for the required opposite unit's Division 2 DG in LCO 3.8.1.c, provided the associated required equipment is inoperable (i.e., one SGT subsystem, primary containmclnt hydrogen recom4ner subsystem, one control room area filtration subsystem, and one control room area ventilation air conditioning subsystem). This exception is intended to allow declaring the opposite unit's Division 2 supported equipment inoperable either in lieu of declaring the opposite unit's Division 2 DG inoperable, or at any time subsequent to entering ACTIONS for an inoperable opposite unit Division 2 DG. This exception is acceptable since, with the opposite unit powered Division 2 equipment inoperable and the associated ACTIONS entered, the opposite unit Division 2 DG provides no additional assurance of meeting the above criteria.

AC power requirements for MODES 4 and 5 and other conditions in which AC sources are required are covered in LCO 3.8.2, "AC Sources-Shutdown."

ACTIONS A1I To ensure a highly reliable power source remains, it is necessary to verify the availability of the remaining required offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in the Required Action not met. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition 0, for two required offsite circuits inoperable, is entered.

Required Action A.2, which only applies if the division cannot be powered from an offsite source, is intended to (continued)

LaSalle 1 and 2 B 3.8.1-7 Revision X

Distribution Systems-Operating B 3.8.7 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.7 Distribution Systems-Operating BASES BACKGROUND The onsite Class 1E AC and DC electrical power distribution system for each unit is divided by division into three independent AC and DC electrical power distribution subsystems. Each unit is also dependent on portions of the opposite unit's Division 2 AC and DC power distribution subsystems.

The primary AC Distribution System consists of three 4.16 kV emergency buses that are supplied from the transmission system by two physically independent circuits. The Division 2 and 3 emergency buses also have a dedicated onsite diesel generator (DG) source, while the Unit 1 and 2 Division 1 buses share an onsite DG source. The Division 1, 2, and 3 4.16 kV emergency buses are normally supplied through the system auxiliary transformer (SAT). In addition to the SAT, Division 1 and 2 can be supplied from the unit auxiliary transformer or the opposite unit's SAT. Control power for the 4.16 kV breakers is supplied from the Class 1E batteries. Additional description of this system may be found in the Bases for LCO 3.8.1, "AC Sources-Operating,"

and the Bases for LCO 3.8.4, "DC Sources-Operating."

The secondary plant AC distribution system includes 480 V ESF load centers and associated loads, motor control centers, and transformers.

There are three independent 125 VDC electrical power distribution subsystems. The Division 2 Class 1E AC and DC electrical power distribution subsystems associated with each unit are shared by each unit since some systems are common to both units. The opposite unit Division 2 Class lE AC and DC electrical power distribution subsystems support equipment required to be OPERABLE by LCO 2.6.3.1, "Primary Containment Hydrogen Recombincr-," LCO 3.6.4.3, "Standby Gas Treatment (SGT) System," LCO 3.7.4, "Control Room Area Filtration (CRAF) System," LCO 3.7.5, "Control Room Area Ventilation Air Conditioning (AC) System," and LCO 3.8.1, "AC Sources-Operating."

(continued)

LaSalle 1 and 2 B 3.8.7 -1 Revision 0

Distribution Systems-Operating B 3.8.7 BASES LCO OPERABLE and certain buses of the opposite unit Division 2 (continued) AC and DC electrical power distribution subsystems are required to be OPERABLE to support the equipment required to be OPERABLE by LCO :x.z.i, LCO 3.6.4.3, LCO 3.7.4, LCO 3.7.5, and LCO 3.8.1. As noted in Table B 3.8.7-1 and Table B 3.8.7-2 (Footnote a), each division of the AC and DC electrical power distribution systems is a subsystem.

Maintaining the Division 1, 2, and 3 AC and DC electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Any two of the three divisions of the distribution system are capable of providing the necessary electrical power to the associated ESF components.

Therefore, a single failure within any system or within the electrical power distribution subsystems does not prevent safe shutdown of the reactor.

OPERABLE AC electrical power distribution subsystems require the associated buses to be energized to their proper voltages. OPERABLE DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage from either the associated battery or charger.

Based on the number of safety significant electrical loads associated with each bus listed in Table B 3.8.7-1 for Unit 1 and Table B 3.8.7-2 for Unit 2, if one or more of the buses becomes inoperable, entry into the appropriate ACTIONS of LCO 3.8.7 is required. Some buses, such as distribution panels, which help comprise the AC and DC distribution systems are not listed in Table B 3.8.7-1 for Unit 1 and Table B 3.8.7-2 for Unit 2. The loss of electrical loads associated with these buses may not result in a complete loss of a redundant safety function necessary to shut down the reactor and maintain it in a safe condition. Therefore, should one or more of these buses become inoperable due to a failure not affecting the OPERABILITY of a bus listed in Table B 3.8.7-1 for Unit 1 and Table B 3.8.7-2 for Unit 2 (e.g., a breaker supplying a single distribution panel fails open), the individual loads on the bus would be considered inoperable, and the appropriate Conditions and Required Actions of the LCOs governing the individual loads would be entered. However, if one or more of these buses is (continued)

LaSalle 1 and 2 B 3.8.7-3 Revision Pr

Primary Containment Hydrogen Recombiners B 3.6.3.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.3. Primary Containment Hydrogen Recombiners BASES BACKGROUND The primary containment hydrogen recombiner iminates the otential breach of primary containment due/o a hydrogen ygen reaction and is part of combustibl gas control re uired by 10 CFR 50.44, "Standards for ombustible Gas Con rol in Light-Water-Cooled Reactors" (Ref. 1), and GDC ', Containment Atmosphere Clean " (Ref. 2). The primar containment hydrogen recombi ers are required to reduce he hydrogen concentration i the primary containment followin a loss of coolant accidet (LOCA). The primary containmen hydrogen recombiners accomplish this by recombining hydrogen and oxyge to form water vapor. The vapor is con nsed and return to the suppression pool, thus eliminating any discharge to the environment. The primary contain ent hydrog recombiner is manually initiated, since flammabi ty limits would not be reached until several hou aft a Design Basis Accident (DBA).

Two 100% capacity in pendent primary containment hydrogen recombiner subsyste re provided and are shared between Unit 1 and Unit 2. Eac consists of controls located in the control room and *n the uxiliary electric equipment room, a power supply, a a recoi iner located in the reactor building. Recyfbination i accomplished by heating a hydrogen air ixture to > 11O0 0F. The resulting water vapor and discharg gases are coole prior to discharge from the unit. Air flows through the u't at 125 cfm, with a blower in the unt providing the motive force. A single recombiner is capa e of maintaining the hyd ogen concentration in primar containment below the 4.0 lume percent (v/o) flam bility limit. Two recombiners are provided to meet the requirement for redundancy and in ependence. Each r ombiner is powered from a separate gineered Safety.

ature bus and is provided with separatg power panel and control panel (with one recombiner powere from Unit 1 and the other recombiner powered from Unit 2).

Emergency operating procedures direct that th hydrogen concentration in primary containment be monito d following a DBA and that the primary containment hydrogen ecombiner

/ ontinued)

L a e 1 and 2 B 3.6.3.1-1 Re sion 0

I Primary Containment Hydrogen Recomb ers 83 .3.1 BASES BACKGROUND\ be manually activated to prevent the primary c tainment (continue atmosphere from reaching a bulk hydrogen conc ntration of 4.0 v/o.

S APPLICABLE e primary containment hydrogen recombi ers provide the SAFETY ANALYSES ca bility of controlling the bulk hyd gen concentration in pri ry containment to less than the ower flammable conce tration of 4.0 v/o following a OBA. This control would event a primary containmen wide hydrogen burn, thus ensuring that pressure and temper ure conditions assumed in the analy s are not exceeded. he limiting DBA relative to hydrogen ge ration is a LOCA.

Hydrogen-may a cumulate in p mary containment following a LOCA as a resul of:

a. A metal steam eacton between the zirconium fuel rod cladding and th r actor coolant; or

b. Radiolytic deco p ition of water in the Reactor Coolant Syste To evaluate the tential f hydrogen accumulation in primary contain ent following a LOCA, the hydrogen generation as function of ti following the initiation of the accident s calculated. Ass ptions recommended by Reference.3 ere complied with to aximize the amount of hydrogen c lculated.

The cal lation confirms that-when the itigating systems are ac uated in accordance with plant p cedures, the peak hydro en concentration in the primary containment remains

' 4 /0 (Ref. 4).

Tie primary containment hydrogen recombiners tisfy riterion 3 of 1O0CFR 50.36(c)(2)(ii).

LCO Two primary containment hydrogen recombiners, inclX ng the associated Residual Heat Removal (RHR) pumps, piping d valves necessary to provide recombiner cooling, must b OPERABLE. This ensures operation of at least one primar containment hydrogen recombiner in the event of a worst ca e single active failure.

(continued)

ISalle 1 and 2 B 3.6.3.1-2 Revision 2

Primary Containment Hydrogen Recombiners B 3.6.3.1 BASE LCO Operation with at least one primary containment h rogen (continue) recombiner subsystem ensures that the post LOCA ydrogen concentration can be prevented from exceeding e flammability limit.

APPLICABILITY I MODES 1 and 2, the two primary contain ent hydrogen re mbiners are required to control the ydrogen conc ntration within primary containme below its flamm ility limit of 4.0 v/o followi g a LOCA, assuming a worst c se single failure.

In MODE 3, both the hydrogen prod ction rate and the total hydrogen pr uction after a LOCA would be less than that calculated fo the DBA LOCA. so, because of the limited time in this M1 E, the probab ity of an accident requiring the primary cont inment hydr gen recombiner is low.

Therefore, the pr ary cont inment hydrogen recombiners are not required in MO 3.

In MODES 4 and 5, the obability and consequences of a LOCA are low due to the pr ure and temperature limitations in these MODES. Theref e, he primary containment hydrogen recombiners are not requir in these MODES.

ACTIONS ALd With one pri ry containment hydr en recombiner inoperable, the inopera e primary containment drogen recombiner must be restor to OPERABLE status withi 30 days. In this conditio , the remaining OPERABLE prim ry containment recombi er is adequate to perform the h rogen control functi n. However, the overall reliabili is reduced beca e a single failure in the OPERABLE rombiner could res t in reduced hydrogen control capabilit . The 30 day Co pletion Time is based on the low probabili of the oecurrence of a LOCA that would generate hydrog n in amounts

/apable of exceeding the flammability limit, the mount of time available after the event for operator action to prevent hydrogen accumulation exceeding this limitnd the low probability of failure of the OPERABLE primary containment hydrogen recombiner.

(continu d)

Las le 1and 2 B36313Rvso B 3.6.3.1-3 Revision 0

Primary Containment Hydrogen Recombiners B 3.6.3 BASES\/

ACTIONS A.1 (continued)

Required Action A.1 has been modified by a Note tating that the provisions of LCO 3.0.4 are not applicable As a esult, a MODE change is allowed when one rec mbiner is i operable. This allowance is provided bec se of the low pro ability of the occurrence of a LOCA th would generate hydr en in amounts capable of exceeding he flammability limit, the low probability of the failur of the OPERABLE recombi r, and the amount of time ava able after a postulate LOCA for operator action t prevent exceeding the flammabili limit.

B.1 and B.2 \

With two primary c ntainment ydrogen recombiners inoperable, the abi ty to rform the hydrogen control function via alternat cap ilities must be verified by administrative means w n 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The alternate hydrogen control capabilities ar rovided by the Primary Containment Vent and Purge System. Th 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time allows a reasonable period of ime t verify that a loss of hydrogen control function do not exi t. In addition, the alternate hydrogen control s stem capabi 'ty must be verified once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereaf r to ensure it continued availability.

Both the initia verification and 11 subsequent verifications ay be performed as a administrative check by examining lo or other information determine the availabilit of the alternate hydrogen control system. It does not m an to perform the Surveillanc s needed to demonstrale OPERABILITY of the alternate drogen control system. If the ability to perform the hydr gen control functi n is maintained, continued operation permitted with wo hydrogen recombiners inoperable for u to 7 days.

Sev days is a reasonable time to allow two hy ogen re ombiners to be inoperable because the hydrogen control f nction is maintained and because of the low prob ility of he occurrence of a LOCA that would generate hydroge in the mounts capable of exceeding the flammability limit.

/ ~(cont n d Lale1 and 2 B 3.6.3.1-4 Revision 0

Primary Containment Hydrogen Reco biners 3.6.3.1 BASES ACTIONS C.1 (continued)

If any Required Action and associated Comr etion Time cannot be met, the plant must be brought to a M E in which the LCO es not apply. To achieve this status the plant must be br ught to at least MODE 3 within 12 h urs. The allowed Cor letion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reaso ble, based on opera ing experience, to reach MODE from full power condit ns in an orderly manner an without challenging plant s tems.

SURVEILLANCE SR 3.6.3.

REQUIREMENTS Performance of system fu tional test for each primary containment hydro en reco iner ensures that the recombiners are OPERABLE and c att in and sustain the temperature necessary for hydrog n ecombination. In particular, this SR requires verificat n that the reaction chamber gas temperature increase t 2 1175 0F in s 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and that significant heater ere s are not burned out by determining that t e curre t in each phase differs by less than or equal to A from th other phases and is within 5Z of the value ob rved in the riginal acceptance test, corrected for ne voltage dif rences.

Operating e erience has shown .tht these components usually pass the S veillance when performe at the 24 month Frequency Therefore, the Frequency as concluded to be acceptab e from a reliability standpoi t.

T s SR requires performance of a resistance o ground test each heater phase to ensure that there are n detectable grounds in any heater phase.- This is accomplish by verifying that the resistance to ground for any he ter phase is 2 1.0E5 ohms within 30 minutes following complet n of SR 3.6.3.1.1.

Operating experience has shown that these components us lly pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

Salle 1 and 2 B 3.6.3.1-5 Revision 0

Primary Containment Hydrogen REFERENCES 10 CFR 50.44.

10 CFR 50, Appendix A, GDC 41.

Regulatory Guide 1.7, Revision 0, March UFSAR, Section 6.2.5.

I I and 2 B 3.6.3.1-6 Revision 0

ATTACHMENT 4-F Markup of Technical Specifications Bases Changes PEACH BOTTOM ATOMIC POWER STATION UNIT 2 REVISED TS BASES PAGES B 3.3-70 B 3.3-74 B 3.3-75 PEACH BOTTOM ATOMIC POWER STATION UNIT 3 REVISED TS BASES PAGES B 3.3-71 B 3.3-75 B 3.3-76

PAM Instrumentation B 3.3.3.1 BASES LC0 (continued)

Instruments: XR-80411A, XR-80411B Dry 1 and suppression chamber hydrogen and oxygen analyze are Category I instruments provided to ect high hydrogen o xygen concentration conditions t represent a potential for tainment breach. This v able is also important in veri ng the adequacy of tigating actions.

The drywell and suppr Sion chamber ydrogen and oxygen analyzer PAM instrumentan co sts of two independent gas analyzers. Each gas analyz can determine either hydrogen or oxygen concentration. he alyzers are capable of

\Zb determining hydrogen ncentration the range of 0 to 30Z by volume and oxy concentration in range of 0 to 10%

by volume. E gas analyzer must be capa e of sampling either the ywell or the suppression chamber. The hydrogen and ox concentration from each analyzer are layed on its sociated control room recorder. Therefore, th AM ecification deals specifically with these portions of e

'analyzer channels.\

11. Suppression Chamber Water Temperature Instruments: TR-8123 A, B TIS-2-2-71 A, B Recorders I Suppression chamber water temperature is a Category I 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 chamber water temperature instrumentation allows operators to detect trends in suppression chamber water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool. Suppression chamber water temperature is monitored by two redundant channels. Each channel is assigned to a separate safeguard power division. Each channel consists of 13 resistance temperature detectors (RTDs) mounted in thermowells installed in the suppression chamber shell below the minimum water level, a processor, and control room recorders. The RTDs are mounted in each of I 13 of the 16 segments of the suppression chamber. The RTD (continued)

PBAPS UNIT 2 8 3.3 -70 .3Revision No.Af-

PAM Instrumentation B 3.3.3.1 BASES (continued)

SURVEILLANCE SR 3.3.3.1.1 REQUIREMENTS Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against 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 instrument channels could be an indication of excessive instrument drift in one of the channels or 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 plant instruments located throughout the plant.

Agreement criteria are determined by the plant 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.

The Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the channels required by the LCO.

SR 3.3.3.1.2 an4f3....

S. These SRs require CHANNEL CALIBRATIONs to be performed. A CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies the channel responds to measured parameter with the necessary range and accuracy. For the PCIV Position Function, the CHANNEL CALIBRATION consists of verifying the remote indication conforms to actual valve position.

(continued)

PBAPS UNIT 2 B 3.3-74 Revision No.,&-

PAM Instrumentaticr; B 3.3.3.3.

BASES SURVEILLANCE &S A .2.3.1.2 and SR 3.3.3.1.3 (continued)

REQUIREMENTS The-92 day Frequency for CHANNEL CALIBRATION of the drywell4 and suppression chamber hydroogen and oxygen analyzers is baoed on vmndor rccommondationc. The 24 month Frequency for CHANNEL CALIBRATION of all ether PAM instrumentation of Table 3.3.3.1-1 is based on operating experience and consistency with the Peach Bottom Atomic Power Station refueling cycles.

REFERENCES 1. Regulatory Guide 1.97, Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident,"

Revision 3, May 1983.

2. NRC Safety Evaluation Report, "Peach Bottom Atomic Power Station, Unit Nos. 2 and 3, Conformance to Regulatory Guide 1.97," January 15, 1988.

3. Letter from G. Y. Suh (NRC) to G. J. Beck (PECo) dated February 13, 1991 concerning "Conformance to Regulatory Guide 1.97 for Peach Bottom Atomic Power Station, Units 2 and 3".

4. Letter from S. Dembek (NRC) to G. A. Hunger (PECO Energy) dated March 7, 1994 concerning 'Regulatory Guide 1.97 - Boiling Water Reactor Neutron Flux Monitoring, Peach Bottom Atomic Power Station (PBAPS),

Units 2 and 3".

PBAPS UNIT 2 B 3.3-75 Revision No.A'

. ........... - -I.----

PAM Instrumentation B 3.3.3.1 BASES b6tf j LCD. 9. 10 k) M

? -

- PI-

- -L

- - II..

I j ^

(continued) ts: XR-90411A, XR-90411B Drywel nd suppression chamber hydrogen and oxyge analyzers Category I instruments provided t detect high hydrogen or o en concentration conditions at represent a potential for con inment breach. This R able is also important in verifyi the adequacy o itigating actions.

The drywell and suppres ion chambe ydrogen and oxygen analyzer PAM instrumentati co ists of two independent gas analyzers. Each gas analyz n determine either hydrogen or oxygen concentration. e ana zers are capable of determining hydrogen centration i the range of 0 to 30%

by volume and oxyg concentration in t range of 0 to 10%

by volume. Eac gas analyzer must be capa K of sampling either the d well or the suppression chamber. The hydrogen and oxyg concentration from each analyzer are played on its a ciated control room recorder. Therefore, t PAM Sp fication deals specifically with these portions oe he balyzer channels.\

11. Suppression Chamber Water Temperature Instruments: TR-9123 A, B TIS-3-2-71 A, B Recorder.s I Suppression chamber water temperature is a Category I 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 chamber water temperature instrumentation allows operators to detect trends in suppression chamber water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool. Suppression chamber water temperature is monitored by two redundant channels. Each channel is assigned to a separate safeguard power division. Each channel consists of 13 resistance temperature detectors (RTDs) mounted in thermowells installed in the suppression chamber shell below the minimum water level, a processor, and control room recorders. The RTDs are mounted in each of I 13 of the 16 segments of the suppression chamber. The RTD (continued)

PBAPS UNIT 3 8 .3.3-71 Revision No.,41'

PAM Instrumentation B 3.3.3.1 BASES (continued)

SURVEILLANCE SR 3.3.3.1.1 REQUIREMENTS Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against 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 instrument channels could be an indication of excessive instrument drift in one of the channels or 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 plant instruments located throughout the plant.

Agreement criteria are determined by the plant 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.

The Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the channels e uu d by the LCO.

SR 3.3.3.1.2 e .

hese SRs require CHANNEL CALIBRATIONs to be performed. A 33 1 l CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies the channel responds to measured parameter with the necessary range and accuracy. For the PCIV Position Function, the CHANNEL CALIBRATION consists of verifying the remote indication conforms to actual valve position.

(continued)

PBAPS UNIT 3 B 3.3-75 Revision No.2"

PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.2 and SR 3.3.3.1.3 (continued)

REQUIREMENTS The g2 day Fretuncy fortCHANNEL. CelTA'TION of-the dryw:o4_

and suppresvion ihamber hydro - oJyg-n analyzers -I n

based on vendor recommendations_ The 24 month Frequency for CHANNEL CALIBRATION of all-ether PAM instrumentation of Table 3.3.3.1-1 is based on operating experience and consistency with the Peach Bottom Atomic Power Station refueling cycles.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident,"

Revision 3, May 1983.

2. NRC Safety Evaluation Report, "Peach Bottom Atomic Power Station, Unit Nos. 2 and 3, Conformance to Regulatory Guide 1.97," January 15, 1988.

3. Letter from G. Y. Sub (NRC) to G. J. Beck (PECo) dated February 13, 1991 concerning "Conformance to Regulatory Guide 1.97 for Peach Bottom Atomic Power Station, Units 2 and 3".

4. Letter from S. Dembek (NRC) to G. A. Hunger (PECO Energy) dated March 7, 1994 concerning "Regulatory Guide 1.97 - Boiling Water Reactor Neutron Flux Monitoring, Peach Bottom Atomic Power Station (PBAPS),

Units 2 and 3".

PBAPS UNIT 3 B 3.3-76 Revision No. X

ATTACHMENT 4-G Markup of Technical Specifications Bases Changes QUAD CITIES NUCLEAR POWER STATION REVISED TS BASES PAGES B 3.3.3.1-6 B 3.3.3.1-7 B 3.3.3.1-10 B 3.3.3.1-11 B 3.3.3.1-12

PAM Instrumentation B 3.3.3.1 BASES LCO 6. Penetration Flow Path Primary Containment Isolation Valve (PCIV) Position (continued) 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 forthe 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. Each penetration is treated separately and each penetration flow path is considered a separate function. Therefore, separate Condition entry is allowed for each inoperable penetration flow path.

The indication for each PCIV is provided at the valve controls in the control room. Each indication 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.

e cDrowell Hndroaen and hxsren Concentration Analvden andlytitorsa Drywell hyd n and oxygen analyzer s m andors are Category I insts tts provided to dean lye gh hydrogen or oxyge concent n ation ditions thy renent potential a

for containment breach. lts var~bl is also important in v erifying the adequacy m of actions.ng Hydrogen and oxygen concentrations are rangred by two independent analyzers and are mon ~dfdin teRtrol room. The drywell hyd r oe xygen analyze rP strumentation consists of toideendent gas analyze. sy~~s. Each gas analyzer syg' cossts of a hydrogen a al zFad an oxygen a yzer. The analyzers are capable ofdet ning hydrsn concentration in the range of OX to 10X and oyn centration in the range of 0% to 10%. Each gas analyze (continued)

Quad Cities 1 and 2 B 3.3.3.1-6 Revi sion /

PAM Instrumentation B 3.3.3.1 BASES LCO Z7--az=.-Drvwell Hvdrogen and Oxygen Concentration ze s an Moi nued) system must capable be t h e drywell. There are two independent rs in the c oom to display the resulicay e ore, the PAM Specificationst t chann callywith this portion of the instrument chal!-_

7./. Torus Water Temperature Torus water temperature is a Type A and Category I 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 torus water temperature instrumentation allows operators to detect trends in torus water temperature in sufficient time to take action to prevent steam quenching vibrations in the torus.

Sixteen temperature sensors are arranged in two groups of eight sensors in independent and redundant channels, located such that there are two sensors (one inner and one outer) located in each of the four quadrants to assure an accurate measurement of bulk water temperature. The range of the torus water temperature channels is 0F to 300 0F.

Thus, two groups of sensors are sufficient to monitor the bulk average temperature of the torus water. Each group of eight sensors is averaged to provide two bulk temperature inputs for PAM. The outputs for the sensors are recorded on two independent recorders in the control room. Both of these recorders must be OPERABLE to furnish two channels of PAM indication. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channels.

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1 and 2.

These variables are related to the diagnosis and preplanned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1 and 2. In MODES 3, 4, and 5, plant conditions are such that the likelihood of an event that would require PAM instrumentation is extremely low; therefore, PAM instrumentation is not required to be OPERABLE in these MODES.

(continued)

Quad Cities 1 and 2 B 3.3.3.1-7 Revision AK'

PAM Instrumentation B 3.3.3.1 BASES ACTIONS (continued)

For the majority of Functions in Table 3.3.3.1-1, if the Required Action and associated Completion Time of Condition C is not 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 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.

Since alternate means of monitoring drywell radiation have been developed and tested, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.6. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. 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.

SURVEILLANCE .s noted at the beginning of the

>, s, the fellewaing as REQUIREMENTS apply to -each PAM instrumentation Function in Table IP P 1 1. a'peRt wharp identified in the cra The Surveillances are modified by a -eeeond-Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the other required channel in the associated Function is OPERABLE. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance is acceptable since it does not significantly reduce the probability of properly monitoring post-accident parameters, when necessary.

(continued)

Quad Cities 1 and 2 B 3.3.3.1-10 Revision

PAM Instrumentation B 3.3.3.1 BASES SURVEI LLANCE SR 3.3.3.1.1 REQUIREMENTS (continued) Performance of the CHANNEL CHECK once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against 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 instrument channels could be an indication of excessive instrument drift in one of the channels or 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 plant instruments located throughout the plant.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including 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.

The Frequency of 31 days is based upon plant operating experience, with regard to channel OPERABILITY and drift, which demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the channels required by the LCO.

SR 3.3.3.1.2 and SR 3.3.3.1.3-A CHANNEL CALIBRATION is performed every 92 days for Functions 7 and C arn every 24 months for all ether functions. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies the channel responds to measured parameter with the necessary range and accuracy. For Function 5, the CHANNEL CALIBRATION shall consist of an electronic calibration of (continued)

Quad Cities 1 and 2 B 3.3.3.1-11 Revision al

PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE SR 3.3.3.1.2 and SR .2.1.2 (continued)

REQUIREMENTS the channel, excluding the detector, for range decades

> 10 R/hour and a one point calibration check of the detector with an installed or portable gamma source for the range decade < 10 R/hour. For Function 6, the CHANNEL CALIBRATION shall consist of verifying that the position indication conforms to actual valve position.

The 92 day Frequeney for CHJANNEL CALIBRATION ef Function; 7' and 8 is based on eoprating Axpehienee. The 24 month Frequency for CHANNEL CALIBRATION of all ethep PAM Instrumentation of Table 3.3.3.1-1 is based on operating experience and consistency with the refueling cycles.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident,"

Revision 2, December 1980.

2. NRC letter, T. Ross (NRC) to H.E. Bliss (Commonwealth Edison Company), "Conformance of Post Accident Monitoring Instrumentation at Quad Cities with Regulatory Guide 1.97," dated August 16, 1988.

Quad Cities 1 and 2 8 3.3.3.1-12 'Revisionle,

ATTACHMENT 5-A REGULATORY COMMITMENTS FOR BRAIDWOOD STATION The following table identifies those actions committed to by Exelon Generation Company, LLC (EGC) in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please direct questions regarding these commitments to Alison Mackellar at (630) 657-2817.

Regulatory Commitments Due Date I Event Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment hydrogen for beyond design basis Relocated to Technical Requirements Manual.

accidents.

ATTACHMENT 5-B REGULATORY COMMITMENTS FOR BYRON STATION The following table identifies those actions committed to by Exelon Generation Company, LLC (EGC) in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please direct questions regarding these commitments to Alison Mackellar at (630) 657-2817.

Regulatory Commitments Due Date / Event Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment hydrogen for beyond design basis Relocated to Technical Requirements Manual.

accidents.

ATTACHMENT 5-C REGULATORY COMMITMENTS FOR CLINTON POWER STATION The following table identifies those actions committed to by AmerGen Energy Company, LLC (AmerGen) in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please direct questions regarding these commitments to Alison Mackellar at (630) 657-2817.

Regulatory Commitments Due Date / Event AmerGen Energy Company, LLC (AmerGen) Implemented by TS Amendment will maintain the capability of monitoring implementation date.

containment hydrogen for beyond design basis Relocated to a licensee controlled document.

accidents.

ATTACHMENT 5-D REGULATORY COMMITMENTS FOR DRESDEN NUCLEAR POWER STATION The following table identifies those actions committed to by Exelon Generation Company, LLC (EGC) in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please direct questions regarding these commitments to Alison Mackellar at (630) 657-2817.

Regulatory Commitments Due Date / Event Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment hydrogen for beyond design basis Relocated to Technical Requirements Manual.

accidents.

Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment oxygen to verify the status of the Relocated to Technical Requirements Manual.

inerted containment.

ATTACHMENT 5-E REGULATORY COMMITMENTS FOR LASALLE COUNTY STATION The following table identifies those actions committed to by Exelon Generation Company, LLC (EGC) in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please direct questions regarding these commitments to Alison Mackellar at (630) 657-2817.

Regulatory Commitments Due Date / Event Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment hydrogen for beyond design basis Relocated to Technical Requirements Manual.

accidents.

Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment oxygen to verify the status of the Relocated to Technical Requirements Manual.

inerted containment.

ATTACHMENT 5-F REGULATORY COMMITMENTS FOR PEACH BOTTOM ATOMIC POWER STATION The following table identifies those actions committed to by Exelon Generation Company, LLC (EGC) in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please direct questions regarding these commitments to Alison Mackellar at (630) 657-2817.

Regulatory Commitments Due Date / Event Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment hydrogen for beyond design basis Relocated to Technical Requirements Manual.

accidents.

Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment oxygen to verify the status of the Relocated to Technical Requirements Manual.

inerted containment.

ATTACHMENT 5-G REGULATORY COMMITMENTS FOR QUAD CITIES NUCLEAR POWER STATION The following table identifies those actions committed to by Exelon Generation Company, LLC (EGC) in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments. Please direct questions regarding these commitments to Alison Mackellar at (630) 657-2817.

Regulatory Commitments Due Date / Event Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment hydrogen for beyond design basis Relocated to Technical Requirements Manual.

accidents.

Exelon Generation Company, LLC (EGC) will Implemented by TS Amendment maintain the capability of monitoring implementation date.

containment oxygen to verify the status of the Relocated to Technical Requirements Manual.

inerted containment.

v t e Letter Sequence Request
TAC:MC4491, Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors (Approved, Closed) TAC:MC4495, Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors (Open)
Initiation Request Acceptance... Administration Questions Answers Results Approval, Approval, Approval, Approval, Approval, Approval Other: ML050960472, ML051360005
MONTHYEAR2005-05-19 [Table View]

RS-04-141, Amergen Request for Amendment to Technical Specifications to Eliminate Requirements for Hydrogen Recombiners and Hydrogen/Oxygen Monitors Using the Consolidated Line Item Improvement Process

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Subject:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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RS-04-141, Amergen Request for Amendment to Technical Specifications to Eliminate Requirements for Hydrogen Recombiners and Hydrogen/Oxygen Monitors Using the Consolidated Line Item Improvement Process

Text

Subject:

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

1.0 INTRODUCTION

2.0 DESCRIPTION

3.0 BACKGROUND

5.0 TECHNICAL ANALYSIS

6.0 REGULATORY ANALYSIS

10.0 REFERENCES

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