Text

Application for Technical Specification Improvement to Eliminate Requirements for Hydrogen Recombiners and Hydrogen Monitors Using the Consolidated Line Item Improvement Process
	ML042650363
Person / Time
Site:	Millstone, Surry, North Anna
Issue date:	09/08/2004
From:	Hartz L; Dominion, Dominion Resources
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	04-386
	Download: ML042650363 (105)
	v • d • e

Dominion Resources Scrvices, Inc.

2 D

5000 Dominion Boulevard. Glen Allen, VA 23060 Dominion September 8, 2004 United States Nuclear Regulatory Commission Serial No.04-386 Attention: Document Control Desk NL&OS/SLW R1 Washington, D. C. 20555-0001 Docket Nos.

50-280, 281 50-338, 339 50-336,423 License Nos. DPR-32, 37 NPF-4, 7 DPR-65 NPF-49 VIRGINIA ELECTRIC AND POWER COMPANY DOMINION NUCLEAR CONNECTICUT, INC.

SURRY POWER STATION UNITS 1 AND 2 NORTH ANNA POWER STATION UNITS 1 AND 2 MILLSTONE POWER STATION UNITS 2 AND 3 APPLICATION FOR TECHNICAL SPECIFICATION IMPROVEMENT TO ELIMINATE REQUIREMENTS FOR HYDROGEN RECOMBINERS AND HYDROGEN MONITORS USING THE CONSOLIDATED LINE ITEM IMPROVEMENT PROCESS Pursuant to 10 CFR 50.90, Virginia Electric and Power Company (Dominion) and Dominion Nuclear Connecticut, Inc. (DNC) hereby request amendments to the Technical Specifications (TS) for Surry Power Station Units 1 and 2, North Anna Power Station Units 1 and 2, and Millstone Power Station Units 2 and 3. The proposed amendments will delete the TS requirements related to hydrogen recombiners (North Anna and Millstone only), and hydrogen 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 changes are consistent with Revision 1 of NRC-approved Industry/Technical Specification Task Force (TSTF) Standard Technical Specification Change Traveler, TSTF-447, "Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors." The availability of this TS improvement was announced in the Federal Register on September 25, 2003 as part of the consolidated line item improvement process (CLIIP).

The proposed TS changes are provided in Attachment 1 for North Anna Power Station Units 1 and 2, Attachment 2 for Surry Power Station Units 1 and 2, Attachment 3 for Millstone Power Station Unit 2, and Attachment 4 for Millstone Power Station Unit 3.

Within each proposed change, Attachment A provides a description of the proposed change, the requested confirmation of applicability, and plant-specific verifications and commitments. Attachment B provides the existing TS pages marked-up to show the proposed change, and Attachment C provides revised, clean TS pages. Implementation of TSTF-447 also involves various changes to the TS Bases. The TS Bases changes

will be submitted with a future update in accordance with North Anna Units 1 and 2 TS 5.5.13, Millstone Unit 2 TS 6.23, and Millstone Unit 3 TS 6.18, "Technical Specifications (TS) Bases Control Program." The Surry TS bases will be updated in accordance with Dominion's Technical Specifications change management procedure. The proposed changes to the TS Bases are provided for information only in Attachment D.

Since the purpose of the CLIIP is to streamline the license amendment review process involving TSTF changes applicable to multiple plants, and at the same time facilitate efficient NRC staff review of licensee submittals, Dominion and DNC request that the NRC review of the attached license amendment requests be performed by the same staff person. Approval of the proposed license amendments is requested by June 24, 2005, with the amendments being implemented within 60 days of approval.

In accordance with 10 CFR 50.91, a copy of this application, with attachments, is being provided to the designated State Officials.

If you should have any questions regarding this submittal, please contact Dave Sommers at (804) 273-2823.

Sincerely, Leslie N. Hartz Vice President - Nuclear Engineering Virginia Electric and Power Company and Dominion Nuclear Connecticut, Inc.

Attachments:

1. Amendment request for North Anna Power Station Units 1 and 2

2. Amendment request for Surry Power Station Units 1 and 2

3. Amendment request for Millstone Power Station Unit 2

4. Amendment request for Millstone Power Station Unit 3.

cc:

U. S. Nuclear Regulatory Commission Region I 475 Allendale Road King of Prussia, PA 19406-1415 US Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, S.W., Suite 23T85 Atlanta, Georgia 30303

Mr. S. R. Monarque Senior Project Manager U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Mail Stop 8H1 12 Rockville, MD 20852-2738 Mr. V. Nerses NRC Senior Project Manager U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Mail Stop 8C2 Rockville, MD 20852-2738 Mr. N. P. Garrett NRC Senior Resident Inspector Surry Power Station Mr. M. T. Widmann NRC Senior Resident Inspector North Anna Power Station Mr. S. M. Schneider NRC Senior Resident Inspector Millstone Power Station Commissioner Bureau of Radiological Health 1500 East Main Street Suite 240 Richmond, VA 23218 Director Bureau of Air Management Monitoring and Radiation Division Department of Environmental Protection 79 Elm Street Hartford, CT 06106-5127

SN: 04-386 Docket Nos.: 50-280/281/338/339/336/423

Subject:

Application for Tech Spec Improvement to Eliminate Requirements for Hydrogen Recombiners and Hydrogen Monitors Using the CLIIP COMMONWEALTH OF VIRGINIA

)

COUNTY OF HENRICO

)

The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Leslie N. Hartz, who is Vice President - Nuclear Engineering, of Virginia Electric and Power Company and Dominion Nuclear Connecticut, Inc. She has affirmed before me that she is duly authorized to execute and file the foregoing document in behalf of those companies, and that the statements in the document are true to the best of her knowledge and belief.

Acknowledged before me this Q = day of,6 hz, 2004.

My Commission Expires: a31,

-2a.

Notary Public (SEAL)

IN NORTH ANNA POWER STATION UNITS 1 AND 2 Technical Specifications Change Request Hydrogen Recombiners and Containment Hydrogen Analyzers -A -B -C Attachment I -D Description and Assessment Mark-Up of Technical Specifications Proposed Technical Specifications Mark-Up and Proposed Bases

-A Description and Assessment Dominion North Anna Power Station Units I and 2

DESCRIPTION AND ASSESSMENT

1.0 INTRODUCTION

The proposed License amendment deletes Technical Specification (TS) 3.6.9, uHydrogen Recombiners," and references to the containment hydrogen analyzers in TS 3.3.3, 'Post Accident Monitoring (PAM) Instrumentation." 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 containment hydrogen analyzers resulted in formatting changes to other TS, which were otherwise unaffected by this proposed amendment.

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

2.0 DESCRIPTION

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

TS 3.3.3 Surveillance Requirement 3.3.3.2 Deleted Table 3.3.3-1 Item 12, Containment Hydrogen Analyzers Deleted TS 3.6.9 Hydrogen Recombiners Deleted Other TS changes included in this application are limited to formatting changes that resulted directly from the deletion of the above requirements related to hydrogen recombiners and containment hydrogen analyzers.

As described in NRC-approved Revision 1 of TSTF-447, the changes to TS requirements results in changes to various TS Bases sections. The associated Bases changes are attached for your information. The TS Bases changes will be submitted with a future update in accordance with TS 5.5.11, "Technical Specifications (TS) Bases Control Program."

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.

5.0 TECHNICAL ANALYSIS

Dominion has reviewed the Safety Evaluation (SE) published September 25, 2003 (68 FR 55416) as part of the CLIIP Notice of Availability. This verification included a review of the NRC staff's SE, as well as the supporting information provided to support TSTF-447. Dominion has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to North Anna Power Station, Units 1 and 2 and justify this amendment for the incorporation of the changes to the North Anna TS.

6.0 REGULATORY ANALYSIS

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

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, Dominion is making the following verifications and regulatory commitments:

1. Dominion has verified that a containment hydrogen analyzer system capable of diagnosing beyond design-basis accidents is installed at North Anna Units 1 and 2 and is making a regulatory commitment to maintain that capability. The containment hydrogen analyzer will be included in the North Anna Units 1 and 2 Technical Requirements Manual. This regulatory commitment will be implemented with the proposed amendment implementation.

2. Dominion does not intend to relocate the current TS requirements for the hydrogen recombiners into another Licensee controlled document. Changes to the North Anna Power Station Units 1 and 2 UFSAR sections describing the use of hydrogen recombiners for combustible gas control will be made under the 10 CFR 50.59 process.

3. North Anna Units 1 and 2 do not have inerted containments.

4. The commitments made by this letter supersede the previous commitments made in support of addressing NUREG-0737 requirements associated with Containment Hydrogen Analyzers and Hydrogen Recombiners.

7.0 NO SIGNIFICANT HAZARDS CONSIDERATION Dominion has reviewed the proposed no significant hazards consideration determination published on September 25, 2003 (68 FR 55416) as part of the CLIIP.

Dominion has concluded that the proposed determination presented in the notice is applicable to North Anna Units 1 and 2 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (a).

8.0 ENVIRONMENTAL EVALUATION Dominion has reviewed the environmental evaluation included in the model SE published on September 25, 2003 (68 FR 55416) as part of the CLIIP. Dominion has concluded that the staff's findings presented in that evaluation are applicable to North Anna Units 1 and 2 and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. Dominion is proposing TS changes consistent with TSTF-447 and the NRC staff's model SE published on September 25, 2003 (68 FR 55416). North Anna's TS are worded slightly different than the TSTF Westinghouse Owners Group (WOG) example but the information intended to be deleted is the same.

10.0 REFERENCES

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

-B Mark-up of Technical Specifications Dominion North Anna Power Station Units I and 2

TECHNICAL SPECIFICATIONS TABLE OF CONTENTS 3.4 3.4.10 3.4.11 3.4.12 3.4.13 3.4.14 3.4.15 3.4.16 3.4.17 3.4.18 3.4.19 3.5 3.5.1 3.5.2 3.5.3 3.5.4 3.5.5 3.5.6 3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6 3.6.7 3.6.8 3.6.9 REACTOR COOLANT SYSTEM (RCS) (continued)

Pressurizer Safety Valves.

Pressurizer Power Operated Relief Valves (PORVs)..

Low Temperature Overpressure Protection (LTOP)

System RCS Operational LEAKAGE.

RCS Pressure Isolation Valve (Pky) Leakage..

RCS Leakage Detection Instrumentation.....

RCS Specific Activity.............

RCS Loop Isolation Valves...........

RCS Isolated Loop Startup...........

RCS Loops-Test Exceptions...........

i

..3.4.10-1

... 3.4.11-1

.3.4.12-1 3.4.13-1

.3.4.14-1

..3.4.15-1

..3.4.16-1 3.4.17-1 3.4.18-1

... 3.4.19-1 EMERGENCY CORE COOLING SYSTEMS (ECCS).

Accumulators...........

ECCS-Operating..........

ECCS-Shutdown.

Refueling Water Storage Tank (RWST)

Seal Injection Flow........

Boron Injection Tank (BIT)

CONTAINMENT SYSTEMS..........

Containment..

Containment Air Locks.

Containment Isolation Valves...

Containment Pressure.......

Containment Air Temperature....

Quench Spray (QS) System Recirculation Spray (RS) System.

Chemical Addition System.....

Hydrogcn Recombiners........

... 3..5.1-1 3.5.1-1 3.5.2-1 3.5.3-1 3.5.4-1 3.5.5-1 3.5.6-1 3.6.1-1

......... 3.6.1-1 3.6.2-1 3.6.3-1 3.6.4-1 3.6.5-1 3.6.6-1 3.6.7-1 3.6.8-1 A

I

-~.'

1 3.7 3.7.1 3.7.2 3.7.3 3.7.4 3.7.5 3.7.6 3.7.7 3.7.8 3.7.9 PLANT SYSTEMS.....

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

. 3.7.1-1 Main Steam Trip Valves (MSTVs)

.3.7.2-1 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs),

Main Feedwater Regulating Valves (MFRVs),

and Main Feedwater Regulating Bypass Valves (MFRBVs).

.3.7.3-1 Steam Generator Power Operated Relief Valves (SG PORVs)

.s....

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

. 3.7.5-1 Emergency Condensate Storage Tank (ECST)

...... 3.7.6-1 Secondary Specific Activity............. 3.7.7-1 Service Water (SW) System.............. 3.7.8-1 Ultimate Heat Sink (UHS)

.............. 3.7.9-1 North Anna Units 1 and 2 i i Amendments 231/212

PAM Instrumentation 3.3.3 SURVEILLANCE REQUIREMENTS NOTE - - - - - - - - - - - - - - - -

SR 3.3.3.1 and SR 3.3.3.3 apply to each PAM instrumentation Function in Table 3.3.3-1 except SR 3.3.3.3 does not apply to Iteml 10.and 1&4 SR 3.3.3.2 applic-only to Item 12-SR 3.3.3.4 applies only to Item 10.

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 Perferm CIIANNEL CALIDRATIO8N.C 9c days SR 3.3.3.3

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

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

18 months SR 3.3.3.4 Perform TADOT.

18 months North Anna Units 1 and 2 3.3.3-2 Amendments 241JB242_e

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

Post Accident Monitoring Instrumentation FUNCTION REQUIRED CHANNELS

1. Power Range Neutron Flux 2

2. Source Range Neutron Flux 2

3. Reactor Coolant System (RCS) Hot Leg Temperature (Wide Range) 2

4. RCS Cold Leg Temperature (Wide Range) 2

5. RCS Pressure (Wide Range) 2

6. Inadequate Core Cooling Monitoring (ICCM) System 6.a. Reactor Vessel Level Instrumentation System (RVLIS) 2 6.b. RCS Subcooling Margin Monitor 2

6.c.1 Core Exit Temperature-Quadrant I 2(c) 6.c.2 Core Exit Temperature-Quadrant 2 2"'

6.c.3 Core Exit Temperature-Quadrant 3 2 "'

6.c.4 Core Exit Temperature-Quadrant 4 2 "'

7. Containment Sump Water Level (Wide Range) 2

8.

Containment Pressure 2

9. Containment Pressure (Wide Range) 2

10. Penetration Flow Path Containment Isolation Valve Position 2 per penetration flow path(")(b')

11. Containment Area Radiation (High Range) 2

12. Co 9t a i mme mt lbdi-gem Amal;e-1cs9-

-D.cl-r-2i

13. Pressurizer Level 2

14.

Steam Generator (SG)

Water Level (Wide Range) 2

15. SG Water Level (Narrow Range) 2 per SG

16.

Emergency Condensate Storage Tank Level 2

17.

SG Pressure 2 per SG

18. High Head Safety Injection Flow 2

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

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

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

North Anna Units 1 and 2 3.3.3-3 Amendments 3,,e

equired tion and

' associa ted lk~petion Xime not met North Anna Units I and 2 3.6.9-1 Amendments-2431-#+/-

-SURVEILLANCE REQUIREQ Hydrogen Recombiner

.6.9 SURVE C

FREQUENCY SURŽAAQ FREQUENCY SR 3.6.9.2 ually examine each n recombiner enc re and verify there is evidence of abno onditions.

18 mO SR 3.6.

Perfonm a resistanc round test for h heater phase.

1 nths A-t J. (6+,c North Anna Units 1 and 2 3.6.9-2 Amendments e31jM1

-C Proposed Technical Specifications Dominion North Anna Power Station Units 1 and 2

TECHNICAL SPECIFICATIONS TABLE OF CONTENTS 3.4 3.4.10 3.4.11 3.4.12 3.4.13 3.4.14 3.4.15 3.4.16 3.4.17 3.4.18 3.4.19 3.5 3.5.1 3.5.2 3.5.3 3.5.4 3.5.5 3.5.6 3.6 3.6.1 3.6.2 3.6.3 3.6.4 3.6.5 3.6.6 3.6.7 3.6.8 3.7 3.7.1 3.7.2 3.7.3 3.7.4 3.7.5 3.7.6 3.7.7 3.7.8 3.7.9 REACTOR COOLANT SYSTEM (RCS) (continued)

Pressurizer Safety Valves...........

Pressurizer Power Operated Relief Valves (PORVs)

Low Temperature Overpressure Protection (LTOP)

System..

RCS Operational LEAKAGE.

RCS Pressure Isolation Valve (PIV) Leakage RCS Leakage Detection Instrumentation.....

RCS Specific Activity.............

RCS Loop Isolation Valves...........

RCS Isolated Loop Startup...........

RCS Loops-Test Exceptions...........

...3.4.10-1

...3.4.11-1

.3.4.12-1

...3.4.13-1

...3.4.14-1

...3.4.15-1

...3.4.16-1

...3.4.17-1

...3.4.18-1

...3.4.19-1 EMERGENCY CORE COOLING SYSTEMS (ECCS).......... 3.5.1-1 Accumulators.................... 3.5.1-1 ECCS-Operating

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

3.5.3-1 Refueling Water Storage Tank (RWST).

3.5.4-1 Seal Injection Flow.................. 3.5.5-1 Boron Injection Tank (BIT)

............. 3.5.6-1 CONTAINMENT SYSTEMS................... 3.6.1-1 Containment..

3.6.1-1 Containment Air Locks.

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

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

................ 3.6.4-1 Containment Air Temperature............. 3.6.5-1 Quench Spray (QS)

System

.............. 3.6.6-1 Recirculation Spray (RS) System........... 3.6.7-1 Chemical Addition System.............. 3.6.8-1 I

PLANT SYSTEMS.......

3.7.1-1 Main Steam Safety Valves (MSSVs)

.3.7.1-1 Main Steam Trip Valves (MSTVs) 3.7.2-1 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs),

Main Feedwater Regulating Valves (MFRVs),

and Main Feedwater Regulating Bypass Valves (MFRBVs) 3.7.3-1 Steam Generator Power Operated Relief Valves (SG PORVs) 3.7.4-1 Auxiliary Feedwater (AFW) System.

......... 3.7.5-1 Emergency Condensate Storage Tank (ECST).

..... 3.7.6-1 Secondary Specific Activity............. 3.7.7-1 Service Water (SW) System.............. 3.7.8-1 Ultimate Heat Sink (UHS)

.............. 3.7.9-1 North Anna Units 1 and 2 i i

PAM Instrumentation 3.3.3 SURVEILLANCE REQUIREMENTS

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

SR 3.3.3.1 and SR 3.3.3.3 apply to each PAM instrumentation Function in Table 3.3.3-1 except SR 3.3.3.3 does not apply to Item 10. SR 3.3.3.4 applies only to Item 10.

I 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 Not Used SR 3.3.3.3

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

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION.

18 months SR 3.3.3.4 Perform TADOT.

18 months I

North Anna Units 1 and 2 3.3.3-2

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

Post Accident Monitoring Instrumentation FUNCTION REQUIRED CHANNELS

1. Power Range Neutron Flux

2. Source Range Neutron Flux

3. Reactor Coolant System (RCS) Hot Leg Temperature (Wide Range)

4. RCS Cold Leg Temperature (Wide Range)

5. RCS Pressure (Wide Range)

6. Inadequate Core Cooling Monitoring (ICCM) System 6.a. Reactor Vessel Level Instrumentation System (RVLIS) 6.b. RCS Subcooling Margin Monitor 6.c.1 Core Exit Temperature-Quadrant I 6.c.2 Core Exit Temperature-Quadrant 2 6.c.3 Core Exit Temperature-Quadrant 3 6.c.4 Core Exit Temperature-Quadrant 4

7. Containment Sump Water Level (Wide Range)

8. Containment Pressure

9. Containment Pressure (Wide Range)

10. Penetration Flow Path Containment Isolation Valve Position

11. Containment Area Radiation (High Range)

12. Deleted

13. Pressurizer Level

14. Steam Generator (SG) Water Level (Wide Range)

15. SG Water Level (Narrow Range)

16. Emergency Condensate Storage Tank Level

17. SG Pressure

18. High Head Safety Injection Flow 2

2 2

2.

2 2

2 2(c) 2(c) 2(c) 2 2

2 2 per penetration 2

flow path(a)(b) l 2

2 2 per SG 2

2 per SG 2

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

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

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

North Anna Units 1 and 2 3.3.3-3

Attachment I -D Mark-Up and Proposed Bases (For Information Only)

Dominion North Anna Power Station Units 1 and 2

TECHNICAL SPECIFICATIONS BASES TABLE OF CONTENTS B 3.4 B 3.4.12 B 3.4.13 B 3.4.14 B 3.4.15 B 3.4.16 B 3.4.17 B 3.4.18 B 3.4.19 B 3.5 B 3.5.1 B 3.5.2 B 3.5.3 B 3.5.4 B 3.5.5 B 3.5.6 REACTOR COOLANT SYSTEM (RCS) (continued)

Low Temperature Overpressure Protection (LTOP) System.............

RCS Operational LEAKAGE..

RCS Pressure Isolation Valve (PIV) Leakage RCS Leakage Detection Instrumentation...

RCS Specific Activity...........

RCS Loop Isolation Valves.........

RCS Isolated Loop Startup.........

RCS Loops-Test Exceptions.........

....B 3.4.12-1

....B 3.4.13-1

....B 3.4.14-1

.B 3.4.15-1

.B 3.4.16-1 B 3.4.17-1

..B 3.4.18-1 B 3.4.19-1 EMERGENCY CORE COOLING SYSTEMS (ECCS).

Accumulators ECCS-Operating..........

ECCS-Shutdown.

Refueling Water Storage Tank (RWST)

Seal Injection Flow........

Boron Injection Tank (BIT)

... B 3.5.1-1 B 3.5.1-1

....... B 3.5.2-1

...... B 3.5.3-1

.B 3.5.4-1

.. B 3.5.5-1

........ B 3.5.6-1 B 3.6 B 3.6.1 B 3.6.2 B 3.6.3 B 3.6.4 B 3.6.5 B 3.6.6 B 3.6.7 B 3.6.8 e 3.6.9 CONTAINMENT SYSTEMS...........

Containment..

Containment Air Locks;.

Containment Isolation Valves.

Containment Pressure..

Containment Air Temperature.....

Quench Spray (QS) System......

Recirculation Spray (RS) System...

Chemical Addition System......

. B 3.6.1-1

. B 3.6.2-1

. B 3.6.3-1

. B 3.6.4-1

. B 3.6.5-1

. B 3.6.6-1

. B 3.6.7-1

. B 3.6.8-1

. B 3.6.9 -

"Ak'rlrnnn mhin r

-e-B 3.7 B 3.7.1 B 3.7.2 B 3.7.3 B 3.7.4 B 3.7.5 B 3.7.6 B 3.7.7 B 3.7.8 B 3.7.9 B 3.7.10 B 3.7.11 PLANT SYSTEMS........

Main Steam Safety Valves (MSSVs).

Main Steam Trip Valves (MSTVs)

Main Feedwater Isolation Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs),

Main Feedwater Regulating Valves (MFRVs),

and Main Feedwater Regulating Bypass Valves (MFRBVs).............

Steam Generator Power Operated Relief Valves (SG PORVs)

Auxiliary Feedwater (AFW) System.

Emergency Condensate Storage Tank (ECST)

Secondary Specific Activity.........

Service Water (SW)

System..........

Ultimate Heat Sink (UHS)..w.t.h.e.r.R...

Main Control Room/Emergency Switchgear Room (MCR ESGR) Emergency Ventilation System (EVS)-MODES 1, 2, 3, and 4.......

Main Control Room/Emergency Switchgear Room (MCR/ESGR) Air Conditioning System (ACS)

... B 3.7.1-1

... B 3.7.2-1

... B 3.7.3-1

... B

... B 3.7.4-1 3.7.5-1 3.7.6-1 3.7.7-1 3.7.8-1 3.7.9-1

...B 3.7.10-1

...B 3.7.11-1 North Anna Units 1 and 2 11i Rev isi on<

PAM Instrumentation B 3.3.3 BASES LCO

11. Containment Area Radiation (High Range)

(continued)

Containment Area Radiation is provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans.

Containment radiation level is used to determine if adverse containment conditions exist.

12> ontainment HY&Ken Analyzers ont nt drogen ana s

e provie

-elcz g

hydrogen conc;M tion conditions t

~s'ersent a

potential forsn anet breach frz>ghdoe exposisS~7Vi vriable is :1efprat nv;1~n he quacy of mitigati ctions. The conment t~rsnanalyzers dabewee

13. Pressurizer Level

( de Pressurizer Level is used to determine whether to terminate SI, if still in progress, or to reinitiate SI if it has been stopped. Knowledge of pressurizer water level is also used to verify the unit conditions necessary to establish natural circulation in the RCS and to verify that the unit is maintained in a safe shutdown condition.

14, 15. Steam Generator Water Level (Wide and Narrow Ranges)

SG Water Level is provided to monitor operation of decay heat removal via the SGs. Both wide and narrow ranges are Category I indications of SG level. The wide range level covers a span of +7 to -41 feet from nominal full load water level. The narrow range instrument covers from +7 to -5 feet of nominal full load water level.

The level signals are inputs to the unit computer, control room indicators, and the Auxiliary Feedwater System.

SG Water Level is used to:

identify the affected SG following a tube rupture;

verify that the intact SGs are an adequate heat sink for the reactor; (continued)

North Anna Units 1 and 2 B 3.3.3-9 Revisionda

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

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

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

D.1 and D.2 If the Required Action and associated Completion Time of Condition D 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 .

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

SURVEILLANCE A Note has been added to the SR Table to clarify that REQUIREMENTS SR 3.3.3.1 and SR 3.3.3.3 apply to each PAM instrumentation Function in Table 3.3.3-1 with the exception that SR 3.3.3.3 is not required to be performed on the containment hydrogen' analycrs or the containment isolation valve position indication. SR 3.3.3.2 is rqguired to be performed on the containmeRnt hydrogen analyzer;. SR 3.3.3.4 is required for the containment isolation valve position indication.

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 (continued)

North Anna Units 1 and 2 B 3.3.3-12 Revision 84-

PAM Instrumentation B 3.3.3 BASES SURVEILLANCE SR 3.3.3.1 (continued)

REQUIREMENTS channels. It is'based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL'CALIBRATION. The high radiation instrumentation should be compared to similar unit instruments located throughout the unit.

Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing'equipment has drifted outside its limit. If the channels are within the criteria, it is an indication that the channels are OPERABLE.

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 CHANN CALIBRATI is performed o t e containment hydro analyzer every 92 days a uses a gas sol ion con ining a o volume percent 0.25%) of hydr en and a s ple of fo volume percent Kf 0.25%) of hydr en with the alance of ach gas sample being nitrogen. Th containment hydrogen nalyzer heat tr ae system is ver' ied OPERABLE as a par f this surveill,ace.

SR 3.3.3.3 elm.e 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 (continued)

North Anna Units 1 and 2 B 3.3.3-13 Revi s ion -Oe_

B 3.6 0NTAINMENT STEMS B 3.6.9 drogen Rec iners ASES Ildrogern combiners B 3.6.9 B GROUND The functio f the hydrog recombiners is to elimin e the otential bre h of contain nt due to a drogen oxyg r ction.

Per CFR 50.44, Standards fo Combustible as Control Syste in Light-Wa r-Cooled Rea tors (Ref. 1 and UFSAR, Chapter

, "Containm t Atmosphere leanup" (Re 2),

hydrogen ecombiners a e required t reduce the h rogen concentra on in the co ainment foil ing a loss o coolant accident (L ). The rec biners accom ish this by recombining drogen and o gen to form ater vapor.

e por is retur ed to contai nt, thus el inating any d charge to th environment. The hydrogen ecombiners a man illy initiate since fla le limits wo Id not be reac d until seve I days afte a Design Bas Accident (DBA).

Two 100% apacity inde ndent hydro recombiner ystems are provid. The two sy ems are shar with the ot r unit.

Each system onsists of c trols locat in the rec iner ault, a powe supply and recombiner.

combination *s complished b heating a by gen air mi ure to great th or equal to l100F. The sulting wate vapor and dis arge gases a cooled pria to discharg from the recoin Pner. A sing recombiner capable of aintaiiing the by ogen concent tion in con inment below he 4.0 vol e percent (v flanmmabili limit. Two combiners are provi d to meet th requirement or redundanc and independen. Each recoin er is powerd from a sep ate Emergency Di el Generato bus, is capa e of being p wered om any Eme ncy Diesel G erator bus, nd is provid w h a separate ower panel a d control pa 1.

APPLICABLE The h rogen recom - ers provide or the capab lity of SAFETY ANAL ES control ing the bulk ydrogen conc tration in ntainment to less an the lowe flammable co entration o 4.0 v/o following DBA. This c trol would p vent a cont mnent wide hydrog burn, thus nsuring the essure and emperature a sumed in the nalyses are ot exceeded.

he (conti ed)

\\6th Anna U I and 2 1 B 3.

\\ vision 0 (dJet !e4-e

Hydroge Recombiners B 3.6.9 BASES APP CABLE limiting DB relative to drogen gener ion is a LOC S ETY ANALYSES Hydrogen m accumulate containment allowing a L as a (continued) result of

a. A al steam rea ion between he zirconium vel rod cl ding ard th reactor cool t;

b. adiolytic d omposition o water in the eactor Cool t

System (RCS and the con inment sump;

/

c. Hydrogen ri the RCS a the time of e LOCA (i.e.

hydroge dissolved i the reactor olant and h rogen gas i the pressuri r vapor spa

or

d. Cor asion of met s exposed t containment ray and rgency Core ooling Syste solutions.

T evaluate th potential fo hydrogen acc ulation in ontainment f lowing a LOC, the hydrog generation a

function of me followin he initiati of the acci nt is calculated Conservative ssumptions r mmconended by Reference/5 are used t maximize the mount of hyd ogen calculat d.

Based ri the conse ative assump ons used to alculate the hydr gen concentr ion versus t e after a I A, the hy ogen concen ation in the ontainment w ld reach 3

v/o about days after t LOCA and 4 v/o about 1 ay ater if no r combiner was unctioning.

itiating th hydrogen re cnbiners with 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months af er a LOCA wi maintain t hydrogen co centration i the primary containm t below fla bility limit.

The hy rogen recombi ers are desi ed such that with the cons vatively cal lated hydrog generation ates dis ssed above, single reco Iner, placed nto service wis in 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months f the LOCA, i capable of miting the p k drogen conce ration in co ainment to ss than 4.0 /o (Ref. 4). The containment mosphere cle up system containment urge blowers re similarly designed suc that one of two edundant tr ns is an ade ate backup t the redundan ydrogen rec biners.

The hy rogen recombi ers satisfy iterion 3 of/10 CFR 50.3 (2)(ii)

/

orth Anna Unjts 1 and 2 B 3.6. -2 evision 0

e. e

Hydrog RecombinerK 83.6.9 BASE

'\\\\\\\\\\

LCO Two hydrogen re biners must e OPERABLE.

his ensures oper ion of at 1 st one hydro n recombinel in the event f

a wor case singl ctive fail e.

Operatio with at lea one hydroge recombiner sures that the post L CA hydrogen oncentration can be preve ed from exceeding te flammabili limit.

APPLIC ILITY I MODES 1 and. two hydro n recombine are require to con rol the hydr en concentr tion within ntainment be ow its amiability 'mit of 4.0 o following LOCA, assumi a wor case singi ailure.

In MODES and 4, bat the hydroge production te and the total hyd gen produce after a LOCA ould be less than that calculated or the DBA L A. Also, be use of the

'inited time in thes MODES, the obability o an accident quiring the ydrogen rec biners is lok. Therefore, he h rogen recomb ners are not equired in DE 3 or 4.

\\In h ES 5 and 6, he prog o

and conser o ces of a Lo

\\

are ld due to thn ressr mut e emperatetre E itationsi these e oES.

There i adequ te a p iners at hot required these MOa s

\\

f ACT aNS

\\\\\\\\

couldrone conta i ent hydrog recombinr operabl t

T

\\in prable recombner must b ~estored to OQRABLE tui 3

witd 30 days.

this condii on, the remailing OfE thE thydrhy rcombineomin te small perform t hydrogen

\\ contro fntio. Hever, the cvy all reliabi tys

\\\\

reduce tcue a sin efailure ithe OPERA~BL ~ecombiner

\\\\

could reu~ n reduced bdrogen con ~ol capabili g. The

\\\\30 da Copeion Time i based on th availabili §of the

\\ther yrg recombiner,\\he small p bability of lvLOCA

\\ curring (tha would gener te an amount of hydrogen at ex eds the fla bility lim ), and the unt of time ava able after a\\LOCA (shoul one occur) r operator actia to prevent drogen accu lation from exceeding th ortflamma n

y limi3. 9 Reis Il orth Ann its 1 and 2\\

B 3. -3

\\\\

Revisio C1 e,( -Jk-

BASES Recombiner BA With two ydrogen reco, iners inope ble, the ab ity to perform he hydrogen ontrol functon via alte te capabi ities must bgverified by p~ministrativ means withi 1 hoy The altern te hydrogen ntrol capab.ities are pro ded by the ntainment at osphere clea p system co ainment pu blowers. Th 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Comp tion Time al ows reasonable p jod of time verify tha a loss of hy ogen ontrol func on does not st. In add'ion, the al rnate hydrogen co rol system c ability mus be verified nce per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months t ereafter to sure its co inued avail ility.

Both the nitial verif ation and a subsequent verific ions may be erformed as administratve check by examinjg logs or o em informat'n to determi e the avail ility of th alternate h rogen contr system. lt doeyinot mean to erform the S rveillances eded to d

nstrate OPE BILITY of t alternate h drogen cont s stem. If the bility to pgform the hy1ogen control unction is intained, co inued operah on is peniri ed with two hy ogen recombi ems inoperabye for up to days.

Seven days s a reasona e time to a ow two hydr en recombine s to be inop able becaus the hydroge control functio is maintaine and because f the low p ability of the oc rrence of a OCA that wou generate hy, ogen in the amoun s capable of exceeding th flammability limit.

/

Ic IeAkr

BASES I

Hydroge Recombiner B 3.6.9 SURVEIIL CE SR

.6.9.1 (con ' ued)

\\\\\\

REQUIREMES\\\\\\\\

that e ch hydrogen combiner Pu 8 blower op ates for at least 1 minutes. Th, using con inment atmo here air at a flow r e of > 50 sc m, the SR ve ifies tha t e heater temperatu increases t 1100°F wi in 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months d is maintained r at least hours.

erating expe ience has sh n that thes components u ally pa the Survei lance when p formed at t 18 month Fre ency. There re, the Freq ency was con luded to be acce able from a eliability s ndpoint.

\\ SR 3.}.2\\\\\\

This SR en ures there a no physica problems th could affect rec iner operat

n. Credible ailures inc de fan ailure. lossof power, b ckage of the internal flo ssile impact etc.

A v ual inspecti n is sufficX nt to detenn e abnormal cond ions that co id cause suc failures (i. loose wiri or str ctural conne ions, depos s of foreig materials, etc.).

e 18 month equency for his SR was veloped consider' the incide ce of hydrog recombiner failing the SR in epast isl

\\

8 ~~R 3.6.9.3\\\\\\\\

Ths SR require performance f a resista e to ground est for ach heater plase to ensur! that there e no detecta le grou s in any hea er phase. Th is accompl hed by verify g that the sistance to round for an heater phas is > 10 0 ohms aft performanc of SR 3.6.9.

The 18 mon Frequency r this Surv llance was veloped considering he incidenceof hydrogen econbiners iling he SR in the ast is low.

REFERENC

1.

CFR 50.44.

2. UFS, Section 3.37.

3. Regula ry Guide 1. dated 4 UFSAR, S tion 6.2.5.

Marc 10, 1971.

\\,North Anna its I an B3.

.9-5 Revision (IJ-A

~

TECHNICAL SPECIFICATIONS BASES TABLE OF CONTENTS B 3.4 B 3.4.12 B 3.4.13 B 3.4.14 B 3.4.15 B 3.4.16 B 3.4.17 B 3.4.18 B 3.4.19 B 3.5 B 3.5.1 B 3.5.2 B 3.5.3 B 3.5.4 B 3.5.5 B 3.5.6 B 3.6 B 3.6.1 B 3.6.2 B 3.6.3 B 3.6.4 B 3.6.5 B 3.6.6 B 3.6.7 B 3.6.8 B 3.7 B 3.7.1 B 3.7.2 B 3.7.3 B 3.7.4 B 3.7.5 B 3.7.6 B 3.7.7 B 3.7.8 B 3.7.9 B 3.7.10 B 3.7.11 REACTOR COOLANT SYSTEM (RCS) (continued)

Low Temperature Overpressure Protection (LTOP) System.............

RCS Operational LEAKAGE..........

RCS Pressure Isolation Valve (PIV) Leakage RCS Leakage Detection Instrumentation...

RCS Specific Activity...........

RCS Loop Isolation Valves.........

RCS Isolated Loop Startup.........

RCS Loops-Test Exceptions.........

..B 3.4.12-1

.... B 3.4.13-1

.... B 3.4.14-1

....B 3.4.15-1

.... B 3.4.16-1

.... B 3.4.17-1

.... B 3.4.18-1

....B 3.4.19-1 EMERGENCY CORE COOLING SYSTEMS (EC Accumulators........

ECCS-Operating.......

ECCS-Shutdown.

Refueling Water Storage Tank (

Seal Injection Flow.....

Boron Injection Tank (BIT)

CONTAINMENT SYSTEMS.......

Containment...

Containment Air Locks.

Containment Isolation Valves Containment Pressure....

Containment Air Temperature Quench Spray (QS) System.

Recirculation Spray (RS) Syste Chemical Addition System..

... B 3.5.1-1 B3.5.1-1 B 3.5.2-1 B 3.5.3-1 B3.5.4-1

........ B 3.5.5-1

........ B 3.5.6-1 B 3.6.1-1

.B 3.6.1-1

............ B 3.6.2-1

.B 3.6.3-1 B 3.6.4-1

........... B 3.6.5-1 B 3.6.6-1

m.B 3.6.7-1

........... B 3.6.8-1 I

PLANT SYSTEMS.....

Main Steam Safety Valves (MSSVs).

Main Steam Trip Valves (MSTVs)

Main Feedwater Isolation Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs),

Main Feedwater Regulating Valves (MFRVs),

and Main Feedwater Regulating Bypass Valves (MFRBVs)

Steam Generator Power Operated Relief Valves (SG PORVs)

Auxiliary Feedwater (AFW) System Emergency Condensate Storage Tank (ECST)

Secondary Specific Activity.........

Service Water (SW) System..........

Ultimate Heat Sink (UHS)

Main Control Room/Emergency Switchgear Room (MCR/ ESGR) Emergency Ventilation System (EVS)-MODES 1, 2, 3, and 4.......

Main Control Room/Emergency Switchgear Room (MCR/ESGR) Air Conditioning System (ACS)

B 3.7.1-1

... B 3.7.1-1

... B 3.7.2-1

... B 3.7.3-1

... B 3.7.4-1

... B 3.7.5-1

....B 3.7.6-1

... B 3.7.7-1

... B 3.7.8-1

... B 3.7.9-1

...B 3.7.10-1

...B 3.7.11-1 North Anna Units 1 and 2 i i

PAM Instrumentation B 3.3.3 BASES LCO

11. Containment Area Radiation (High Range)

(continued)

Containment Area Radiation is provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans.

Containment radiation level is used to determine if adverse containment conditions exist.

12. Deleted

13. Pressurizer Level Pressurizer Level is used to determine whether to terminate SI, if still in progress, or to reinitiate SI if it has been stopped. Knowledge of pressurizer water level is also used to verify the unit conditions necessary to establish natural circulation in the RCS and to verify that the unit is maintained in a safe shutdown condition.

14, 15. Steam Generator Water Level (Wide and Narrow Ranges)

SG Water Level is provided to monitor operation of decay heat removal via the SGs. Both wide and narrow ranges are Category I indications of SG level. The wide range level covers a span of +7 to -41 feet from nominal full load water level. The narrow range instrument covers from +7 to -5 feet of nominal full load water level.

The level signals are inputs to the unit computer, control room indicators, and the Auxiliary Feedwater System.

SG Water Level is used to:

identify the affected SG following a tube rupture;

verify that the intact SGs are an adequate heat sink for the reactor;

determine the nature of the accident in progress (e.g., verify a SGTR); and

verify unit conditions for termination of SI.

North Anna Units 1 and 2 B 3.3.3-9

PAM Instrumentation B 3.3.3 BASES LCO 14, 15. Steam Generator Water Level (Wide and Narrow Ranges)

(continued)

Operator action is based on the control room indication of SG level. The RCS response during a design basis small break LOCA depends on the break size. For a certain range of break sizes, a secondary heat sink is necessary to remove decay heat. Narrow range level is a Type A variable because the operator must manually raise and control SG level.

16. Emergency Condensate Storage Tank (ECST) Level ECST Level is provided to ensure water supply for auxiliary feedwater (AFW). The ECST provides the ensured safety grade water supply for the AFW System. Inventory is monitored by a 0% to 100% level indication and ECST Level is displayed on a control room indicator.

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

The ECST is the initial source of water for the AFW System. However, as the ECST is depleted, manual operator action is necessary to replenish the ECST.

17. Steam Generator Pressure SG pressure is a Category I variable and provides an indication of the integrity of a steam generator. This indication can provide important information in the event of a faulted or ruptured steam generator.

18. High Head Safety Injection (HHSI) Flow Total HHSI flow to the RCS cold legs is a Type A variable and provides an indication of the total borated water supplied to the RCS. For the small break LOCA, HHSI flow may be the only source of borated water that is injected into the RCS. Total HHSI flow is a Type A variable because it provides an indication to the operator for the RCP trip criteria.

North Anna Units 1 and 2 B 3.3.3-10

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

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

D.1 and D.2 If the Required Action and associated Completion Time of Condition D 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 .

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

SURVEILLANCE A Note has been added to the SR Table to clarify that REQUIREMENTS SR 3.3.3.1 and SR 3.3.3.3 apply to each PAM instrumentation Function in Table 3.3.3-1 with the exception that SR 3.3.3.3 is not required to be performed on containment isolation valve position indication. SR 3.3.3.4 is required for the containment isolation valve position indication.

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 (continued)

North Anna Units 1 and 2 B 3.3.3-12

PAM Instrumentation B 3.3.3 BASES SURVEILLANCE SR 3.3.3.1 (continued)

REQUIREMENTS approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar unit instruments located throughout the unit.

Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. If the channels are within the criteria, it is an indication that the channels are OPERABLE.

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 Not Used SR 3.3.3.3 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. This SR is modified by a Note that excludes neutron detectors. Whenever a sensing element is replaced, the next required CHANNEL CALIBRATION of the CET sensors is accomplished by an inplace cross calibration that compares the other sensing elements with the recently installed sensing element. The Frequency is based on operating experience and consistency with the typical industry refueling cycle.

North Anna Units 1 and 2 B 3.3.3-13

PAM Instrumentation B 3.3.3 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.3.4 SR 3.3.3.4 is the performance of a TADOT of containment isolation valve position indication. This TADOT is performed every 18 months. The test shall independently verify the OPERABILITY of containment isolation valve position indication against the actual position of the valves.

The Frequency is based on the known Functions, and has been shown to be operating experience.

reliability of the acceptable through REFERENCES

1. Technical Report PE-0013.

2. Regulatory Guide 1.97, May 1983.

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

North Anna Units 1 and 2 B 3.3.3-14

SURRY POWER STATION UNITS1 AND2 Technical Specifications Change Request Containment Hydrogen Analyzers -A -B -C -D Description and Assessment Mark-Up of Technical Specifications Proposed Technical Specifications Mark-Up and Proposed Bases

-A Description and Assessment Dominion Surry Power Station Units I and 2

DESCRIPTION AND ASSESSMENT

1.0 INTRODUCTION

The proposed License amendment deletes Technical Specification (TS) 3.7 Instrumentation Systems, Specification F, which provides the TS requirements for the containment hydrogen analyzers and their associated support equipment.

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

2.0 DESCRIPTION

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

TS 3.7 Specification F Deleted Table 4.1-2A Item 21, Containment Hydrogen Analyzers Deleted As described in NRC-approved Revision 1 of TSTF-447, the changes to TS requirements also results in changes to the TS 3.7 Basis section. The associated Basis change is attached for information. The Surry TS basis will be updated in accordance with Dominion's Technical Specification change management procedure.

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.

5.0 TECHNICAL ANALYSIS

Dominion has reviewed the Safety Evaluation (SE) published September 25, 2003 (68 FR 55416) as part of the CLIIP Notice of Availability. This verification included a review of the NRC staffs SE, as well as the supporting information provided to support TSTF-447. Dominion has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to Surry Power Station Units 1 and 2 and justify this amendment for the incorporation of the changes to the Surry TS.

6.0 REGULATORY ANALYSIS

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

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, Dominion is making the following verifications and regulatory commitments:

1. Dominion has verified that a containment hydrogen analyzer system capable of diagnosing beyond design-basis accidents is installed at Surry Units I and 2 and is making a regulatory commitment to maintain that capability. The containment hydrogen analyzers will be included in the Surry Units 1 and 2 Technical Requirements Manual. This regulatory commitment will be implemented with the proposed amendment implementation.

2. Surry Units I and 2 do not have inerted containments.

3. The commitment made by this letter supersedes the previous commitments made in support of addressing NUREG-0737 requirements associated with Containment Hydrogen Analyzers.

7.0 NO SIGNIFICANT HAZARDS CONSIDERATION Dominion has reviewed the proposed no significant hazards consideration determination published on September 25, 2003 (68 FR 55416) as part of the CLIIP.

Dominion has concluded that the proposed determination presented in the notice is applicable to Surry Units I and 2 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (a).

8.0 ENVIRONMENTAL EVALUATION Dominion has reviewed the environmental evaluation included in the model SE published on September 25, 2003 (68 FR 55416) as part of the CLIIP. Dominion has concluded that the staffs findings presented in that evaluation are applicable to Surry Units 1 and 2 and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. Dominion is proposing TS changes consistent with TSTF-447 and the NRC staffs model SE published on September 25, 2003 (68 FR 55416). Surry's TS are worded slightly differently than the TSTF Westinghouse Owners Group (WOG) example but the information intended to be deleted is the same.

10.0 REFERENCES

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

-B Mark-up of Technical Specifications Dominion Surry Power Station Units I and 2

TS 3.7-2

,O4+-4

2. With less than the minimum number of explosive gas monitoring instrumentation channels OPERABLE, take the action shown in Table 3.7-5(a). Exert best efforts to return the instruments to operable status within 30 days and, if unsuccessful, prepare and submit a Special Report to the Commission (Region II) to explain why the inoperability was not corrected in a timely manner.

E. The accident monitoring instrumentation listed in Table 3.7-6 shall be OPERABLE in accordance with the following:

1. With the number of OPERABLE accident monitoring instrumentation channels less than the Total Number of Channels shown in Table 3.7-6, items 1 through 9, either restore the inoperable channel(s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

2. With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum OPERABLE Channels requirement of Table 3.7-6, items I through 9, either restore the inoperable channel(s) to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT SHUTDOWN within the next 12 ho irs.

F. The contai hydrogen analyzers an}d as support equipment shall be BLE in accordance with wing:

1. Two indpde on t hydrogen analyzs e

RABLE during R CRITICAL or POWER N.

a. With one hydro yzer inoperable, restore the e analyzer to

OPstatus within 30 days or be inOT SHUTDOWN within

,hrs.

/

Amendment Nos.-228-and-2B

TS 3.7-3

b. With both hydroge zers inoperable, restore at least one analyz OP u

status within 7 days or be in at least HO N

within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

NOE:

of the hydrogen analyzers includes proper ope the respective Heat Tracing Systen Basis u

ep eJe Instrument Operating Conditions During plant operations, the complete instrumentation system will normally be in service.

Reactor safety is provided by the Reactor Protection System, which automatically initiates appropriate action to prevent exceeding established limits. Safety is not compromised, however, by continuing operation with certain instrumentation channels out of service since provisions were made for this in the plant design. This specification outlines the limiting conditions for operation necessary to preserve the effectiveness of the Reactor Protection System when any one or more of the channels is out of service.

Almost all Reactor Protection System channels are supplied with sufficient redundancy to provide the capability for channel calibration and test at power. Exceptions are backup channels such as reactor coolant pump breakers. The removal of one trip channel on process control equipment is accomplished by placing that channel bistable in a tripped mode (e.g., a two-out-of-three circuit becomes a one-out-of-two circuit). The Nuclear 4, Instrumentation System (NIS) channels are not intentionally placed in a tripped mode j

since the test signal is superimposed on the normal detector signal to test at power. Testing of the NIS power range channel requires: (a) bypassing the dropped-rod protection from NIS, for the channel being tested, (b) placing the AT/ravg protection channel set that is being fed from the NIS channel in the trip mode, and (c) defeating the power mismatch section of Tavg control channels when the appropriate NIS channel is being tested.

However, the Rod Position System and remaining NIS channels still provide the dropped-rod protection. Testing does not trip the system unless a trip condition exists in a concurrent channel.

Amendment Nos. 480 aces'84Q-

TABLE 4.1-2A(CONTINUED)

MINIMUM FREQUENCY FOR EQUIPMENT TESTS UFSAR SECTION REFERENCE DESCRIPTION

19. Primary Coolant System

20. Containment Purge MOV Leakage 21 CH5Ae.mcnt A

s.

L2_A N EL-I CaNNeL e_ Iee..vf TEST Functional Functional FREQUENCY

1. Periodic leakage testing(a)(b) on each valve listed in Specification 3.1.C.7a shall be accomplished prior to entering POWER OPERATION after every time the plant is placed in COLD SHUTDOWN for refueling, after each time the plant is placed in COLD SHUTDOWN for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if testing has not been accomplished in the preceding 9 months, and prior to returning the valve to service after maintenance, repair or replacement work is performed.

Semi-Annual (Unit at power or shutdown) if purge valves are operated during interval(c)

G"08 er 91ayt

hypresen, ACES go_

Il.

c rtrrP WtIRO FORMSr tOW WifeJ z

0 (ne ealmes "Itrra 1

':ill in-11t~ig oulrp Ad S-za Flow 2 273,000 gpm

22. RCS Flow

23. Deletd0)

Once per I 8 months 14 I

(a) To satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if accomplished in accordance with approved procedures and supported by computations showing that the method is capable of demonstrating valve compliance with the leakage criteria.

(b) Minimum differential test pressure shall not be below 150 psid.

(c)

Refer to Section 4.4 for acceptance criteria.

See Specification 4.1.D.

IiD 0.

-C Proposed Technical Specifications Dominion Surry Power Station Units I and 2

TS 3.7-2

2. With less than the minimum number of explosive gas monitoring instrumentation channels OPERABLE, take the action shown in Table 3.7-5 (a). Exert best efforts to return the instruments to operable status within 30 days and, if unsuccessful, prepare and submit a Special Report to the Commission (Region II) to explain why the inoperability was not corrected in a timely manner.

E. The accident monitoring instrumentation listed in Table 3.7-6 shall be OPERABLE in accordance with the following:

1. With the number of OPERABLE accident monitoring instrumentation channels less than the Total Number of Channels shown in Table 3.7-6, items 1 through 9, either restore the inoperable channel(s) to OPERABLE status within 7 days or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

2. With the number of OPERABLE accident monitoring instrumentation channels less than the Minimum OPERABLE Channels requirement of Table 3.7-6, items I through 9, either restore the inoperable channel(s) to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT SHUTDOWN within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Amendment Nos.

TS 3.7-3 Basis Instrument Operating Conditions During plant operations, the complete instrumentation system will normally be in service.

Reactor safety is provided by the Reactor Protection System, which automatically initiates appropriate action to prevent exceeding established limits. Safety is not compromised, however, by continuing operation with certain instrumentation channels out of service since provisions were made for this in the plant design. This specification outlines the limiting conditions for operation necessary to preserve the effectiveness of the Reactor Protection System when any one or more of the channels is out of service.

Almost all Reactor Protection System channels are supplied with sufficient redundancy to provide the capability for channel calibration and test at power. Exceptions are backup channels such as reactor coolant pump breakers. The removal of one trip channel on process control equipment is accomplished by placing that channel bistable in a tripped mode (e.g., a two-out-of-three circuit becomes a one-out-of-two circuit). The Nuclear Instrumentation System (NIS) channels are not intentionally placed in a tripped mode since the test signal is superimposed on the normal detector signal to test at power. Testing of the NIS power range channel requires: (a) bypassing the dropped-rod protection from NIS, for the channel being tested, (b) placing the AT/Tavg protection channel set that is being fed from the NIS channel in the trip mode, and (c) defeating the power mismatch section of Tavg control channels when the appropriate NIS channel is being tested.

However, the Rod Position System and remaining NIS channels still provide the dropped-rod protection. Testing does not trip the system unless a trip condition exists in a concurrent channel.

Amendment Nos.

TABLE 4.1-2A(CONTINUED)

MINIMUM FREQUENCY FOR EQUIPMENT TESTS UFSAR SECTION REFERENCE DESCRIPTION

19. Primary Coolant System

20. Containment Purge MOV Leakage

21. Deleted

22. RCS Flow

23. Deleted TEST Functional Functional Flow 2 273,000 gpm FREQUENCY

1. Periodic leakage testing(a)(b) on each valve listed in Specification 3.I.C.7a shall be accomplished prior to entering POWER OPERATION after every time the plant is placed in COLD SHUTDOWN for refueling, after each time the plant is placed in COLD SHUTDOWN for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months if testing has not been accomplished in the preceding 9 months, and prior to returning the valve to service after maintenance, repair or replacement work is performed.

Semi-Annual (Unit at power or shutdown) if purge valves are operated during interval(c)

I Once per 18 months 14 I

(a) To satisfy ALARA requirements, leakage may be measured indirectly (as from the performance of pressure indicators) if accomplished in accordance with approved procedures and supported by computations showing that the method is capable of demonstrating valve compliance with the leakage criteria.

(b) Minimum differential test pressure shall not be below 150 psid.

(c) Refer to Section 4.4 for acceptance criteria.

See Specification 4.1.D.

El 0

'In

-C

-D Mark-Up and Proposed Bases (For Information Only)

Dominion Surry Power Station Units I and 2

TS 3.7-7 steam line pressure setting limit is set below the full load operating pressure. The safety analysis shows that these settings provide protection in the event of a large steam line break.(3)

Accident Monitoring Instrumentation The operability of the accident monitoring instrumentation in Table 3.7-6 ensures that sufficient information is available on selected plant parameters to monitor and assess these variables during and following an accident. On the pressurizer PORVs, the pertinent channels consist of redundant limit switch indication. The pressurizer safety valves utilize an acoustic monitor channel and a downstream high temperature indication channel. This capability is consistent with the recommendations of Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant Conditions

.During and Following an Accident," December 1975, and NUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short Term Recommendations." Potential 7

gaseous effluent release paths are equipped With radiation monitors to detect and measure concentrations of noble gas fission products in plant gaseous effluents during and following an accident. The gaseous effluent release paths monitored are the process vent stack, ventilation vent stack, main steam safety valve and atmospheric dump valve discharge and the AFW pump turbine exhaust. The potential liquid effluent release paths via the service water discharge from the recirculation spray heat exchangers are equipped with radiation monitors to detect leakage of recirculated containment sump fluid. These radiation monitors and the associated sample pumps are required to operate during the recirculation heat removal phase following a loss of coolant accident in order to detect a passive failure of a recirculation spray heat exchanger tube. These monitors meet the requirements of NUREG-0737.

Instrumentation is provided for monitoring (and controlling) the concentrations of potentially explosive gas mixtures in the Waste Gas Holdup System. The operability and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63 and 64 of Appendix A to 10 CFR Part 50.

Containment Hydrogen Anal Indiccation ogen concentration in the containment a re can be provided in

.C ontrol room over the range of zero to ted rnthydrogen concentration under accident conditions.

Thes ed analyzrs ared by Units 1 andmn Nos. 1O3-n to record the hydrogen conc hrton. a.

\\ Jcl~s Amcndment Nos. 19 mad 193

TS 3.7-8 Hydrogen anal is designed wi e capacity to

n an accurate ample within 30 minutes af itiation of safe njection.

A tra er switch is pro d for Unit 1 t se both analy oror r Unit 2 to e both yzers. In additio each unit's hy en analyzer has transferable eme ency power supply from Uni and Unit 2. T HI11 ensure e cy for each u3n Indication Unit I and Un hydrogen co ntratlof is pro ed on the Unit ost Accid t Monitoring pa and the Unit 2ost Accident M oring panel, tively.

H rogen concenit ion is also re ded on qualifi ecorders. In a tion, each ydrogen analy r is provided wi an alarm for trielhigh hydrog content. These alarms ar ated in the con room.

The s ply lines installe from the contai ent penetration o the hydrogen alyzers h eCategoy I Cla heat tracing ied. The heat ing system rece the same transferable emer ency power as isrovided to the c tainment hydrog analyzers. The heat trace sym is de-energizduring normal tem operation.

on receipt of a after a time delay, ttracing is ener to bring the ing process tem tore to 2 100F. Each at trace circut equipped with RTD to provi d ividual rcuit readout, o -temperature a]

, and control circuit to maintn the process temperatures.

The hy en analyzer he system is ipped with high mperature, loss C.

pow loss of A.C er, loss of con I power, and7f re of automati nitiation Non-Essential Service Water Isolation System K deIYt-e The operability of this functional system ensures that adequate intake canal inventory can be maintained by the Emergency Service Water Pumps. Adequate intake canal inventory provides design service water flow to the recirculation spray heat exchangers and other essential loads (e.g., control room area chillers, charging pump lube oil coolers) following a design basis loss of coolant accident with a coincident loss of offsite power. This system is common to both units in that each of the two trains will actuate equipment on each unit.

Amendment Nos..1 8i-rd*181

TS 3.7-7 steam line pressure setting limit is set below the full load operating pressure. The safety analysis shows that these settings provide protection in the event of a large steam line break.f3 Accident Monitoring Instrumentation The operability of the accident monitoring instrumentation in Table 3.7-6 ensures that sufficient information is available on selected plant parameters to monitor and assess these variables during and following an accident. On the pressurizer PORVs, the pertinent channels consist of redundant limit switch indication. The pressurizer safety valves utilize an acoustic monitor channel and a downstream high temperature indication channel. This capability is consistent with the recommendations of Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant Conditions During and Following an Accident," December 1975, andNUREG-0578, "TMI-2 Lessons Learned Task Force Status Report and Short Term Recommendations." Potential gaseous effluent release paths are equipped with radiation monitors to detect and measure concentrations of noble gas fission products in plant gaseous effluents during and following an accident. The gaseous effluent release paths monitored are the process vent stack, ventilation vent stack, main steam safety valve and atmospheric dump valve discharge and the AFW pump turbine exhaust. The potential liquid effluent release paths via the service water discharge from the recirculation spray heat exchangers are equipped with radiation monitors to detect leakage of recirculated containment sump fluid. These radiation monitors and the associated sample pumps are required to operate during the recirculation heat removal phase following a loss of coolant accident in order to detect a passive failure of a recirculation spray heat exchanger tube. These monitors meet the requirements of NUREG-0737.

Instrumentation is provided for monitoring (and controlling) the concentrations of potentially explosive gas mixtures in the Waste Gas Holdup System. The operability and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63 and 64 of Appendix A to 10 CFR Part 50.

Amendment Nos.

TS 3.7-8 Non-Essential Service Water Isolation System The operability of this functional system ensures that adequate intake canal inventory can be maintained by the Emergency Service Water Pumps. Adequate intake canal inventory provides design service water flow to the recirculation spray heat exchangers and other essential loads (e.g., control room area chillers, charging pump lube oil coolers) following a design basis loss of coolant accident with a coincident loss of offsitc power. This system is common to both units in that each of the two trains will actuate equipment on each unit.

Amendment Nos.

MILLSTONE POWER STATION UNIT 2 Technical Specifications Change Request Hydrogen Recombiners and Monitors -A -B -C -D Description and Assessment Mark-Up of Technical Specifications Proposed Technical Specifications Mark-Up and Proposed Bases

-A Description and Assessment DNC Millstone Power Station Unit 2

DESCRIPTION AND ASSESSMENT

1.0 INTRODUCTION

The proposed License amendment deletes Technical Specification (TS) 3/4.6.4.1, "Combustible Gas Control, Hydrogen Monitors" and TS 3/4.6.4.2, uElectric Hydrogen Recombiners - W". The proposed TS changes support implementation of the revisions to 10 CFR 50.44, uStandards 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 recombiners and hydrogen monitors resulted in numbering and formatting changes to other TS, which were otherwise unaffected by this proposed amendment.

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

2.0 DESCRIPTION

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

TS 3/4.6.4.1 Combustible Gas Control, Hydrogen Monitors Deleted TS 3/4.6.4.2 Combustible Gas Control, Electric Hydrogen Recombiners Deleted Other TS changes included in this application are limited to renumbering and formatting changes that resulted directly from the deletion of the above requirements related to hydrogen recombiners and hydrogen monitors.

As described in NRC-approved Revision I of TSTF-447, the changes to TS requirements and associated renumbering of other TSs results in changes to various TS Bases sections. The associated Bases changes are attached for your information. The TS Bases changes will be submitted with a future update in accordance with TS 6.23, "Technical Specifications (TS) Bases Control Program."

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.

5.0 TECHNICAL ANALYSIS

Dominion Nuclear Connecticut, Inc. (DNC) has reviewed the safety evaluation (SE) published September 25, 2003 (68 FR 55416) as part of the CLIIP Notice of Availability.

This verification included a review of the NRC staffs SE, as well as the supporting information provided to support TSTF-447. DNC has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to Millstone Unit 2 and justify this amendment for the incorporation of the changes to the Millstone Unit 2 TS.

6.0 REGULATORY ANALYSIS

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

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, DNC is making the following verifications and regulatory commitments:

1. DNC has verified that a hydrogen monitoring system capable of diagnosing beyond design-basis accidents is installed at Millstone Unit 2 and is making a regulatory commitment to maintain that capability. The hydrogen monitors will be included in the Millstone Unit 2 Technical Requirements Manual. This regulatory commitment will be implemented with the proposed amendment implementation.

2. Millstone Unit 2 does not have an inerted containment.

3. The commitments made by this letter supersede the previous commitments made in support of addressing NUREG-0737 requirements associated with Hydrogen Monitors and Hydrogen Recombiners.

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

8.0 ENVIRONMENTAL EVALUATION DNC has reviewed the environmental evaluation included in the model SE published on September 25, 2003 (68 FR 55416) as part of the CLIIP. DNC has concluded that the staff's findings presented in that evaluation are applicable to Millstone Unit 2 and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. DNC is proposing TS changes consistent with TSTF-447 and the NRC staffs model SE published on September 25, 2003 (68 FR 55416). Millstone's TS are worded slightly different than the TSTF example but the information intended to be deleted is the same.

10.0 REFERENCES

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

-B Mark-Up of Technical Specifications DNC Millstone Power Station Unit 2

INDEX LIMITING CONDITION FOR OPERATION AND SURVEILANCE REQUIREMENTS SECTION PAGE 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT.......................................

3/4 6-1 Containment Integrity.3/4 6-1 Containment Leakage.3/4 6-2 Containment Air Locks.3/4 6-6 Internal Pressure.

3/4 6-8 Air Temperature.3/4 6-9 JP DELETED 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS..............................

3/4 6-12 Containment Spray and Cooling Systems....................................... 3/4 6-12 DELETED 3/4.6.3 CONTAINMENT ISOLATION VALVES.......................................

3/4 6-15 Containment Ventilation System...........................

3/4 6-19 3/4.6.4 COMBUSTIBLE GAS CONTROL...........................

3/4 6-20 l14ydreogel M eoniter-s..............................................................

DELETEDD Post-Incident Recirculation Systems...........................

3/4 6-24 3/4.6.5 SECONDARY CONTAINMENT...........................

3/4 6-25 Enclosure Building Filtration System...........................

3/4 6-25 Enclosure Building...........................

3/4 6-28 MILLSTONE - UNIT 2 Vil Amendment No. 4104, ia,

20I, 24-Z, I

Septemer"28 198?

)j)

CONTAINMENT SYSTEMS 3/4.6.4 COMbUSTIBLE.GAS.CONTROL.. ::::.;..-.:

i-DROGE:N MsONITORS.

/

LIMITI1i CONDITION POP, OPERATION/

3.6.4.1 Two inedent containment hydrogen monitors shall-be OPERABLE APPLICABILITY: M ES I and 2....

ACTION:'

\\*

a.

With one hydrogen monitor perable, restore the ino able monitor to OPERABLE status within 30 da or be in at least H STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

b.

With both hydrogen monitors inoperable e r at least one monitor to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be t least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMEN

. Z 3)

I 4.6.4.1 Each hydrogen oitor. shall be demonstrated OPERABLE y performanc of a CHANNEL FUNCTION TEST at least onceper 31 days, d at least once per 92 days on a STAGGERED TEST BAS y

perloring a CtHANNEL CALIBRATION using sample gases containing:

a.

e volume percent hydrogen, balance nitrogen.

b. Four volume percent hydrogen, balance nitrogen.

MILLSTONE - UNIT 2 3/4 6-20 Amendment No. 120

i -

-ugu V

1,J is5 "rONTAINMENT SYSTEMS/

ELN RIC HYDROGEN RECOMBINERS - W/

LIMITI NDITION FOR OPERATION 3.6.4.2 Two s rate and independent containment hy ogen recombiner systems shall be ERABLE.

APPLICABILITY: MODES and 2.

ACTION:

With one hydrogen recombiner stem inop able, restore the inoperable system to OPERABLE status withi 30 d or be in HOT STANDBY within the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.4.2 Each hydrogen re mbiner system sha be demonstrated OPERABLE:

a. At least on per 6 months by verifyin during a recombiner system fun lonal test that the minimum ater sheath temper-ature in eases to > 700"F within 90 minut and is maintained for at east 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

b. At ast once per 18 months by:

Performing a CHANNEL CALIBRATION of all recomb er instru-mentation and control circuits.

2. Verifying through a visual examination that there Is o evidence of abnormal conditions within the recombiners (i.e., loose wiring or structural connections, deposits foreign materials, etc.)

MILLSTONE - UNIT 2 3/4 6-21 Rhe-tn~

1L4*

"#g"t+-i7?-

CONT ENT SYSTEMS SURVEILLANCE RE EMENTS (Continued)

3. Verifying u a nec system functional test that the heater sheath erature increases to >l12000F within 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months a intained for at least 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months .

4.

Verifyin e integrity of t heater electrical circuits by per rrning a continuity and Istance to ground test I

jately following the above req ed functional test.

e resistance to ground for any heater ase shall be >

/

lOOOO ohms.

It t

A"%"

"e-do, MILLSTONE -

UNIT 2 3/4 6-22

-C Proposed Technical Specifications DNC Millstone Power Station Unit 2

INDEX LIMITING CONDITION FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION PAGE 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT.....................................

3/4 6-1 Containment Integrity.....................................

3/4 6-1 Containment Leakage.....................................

3/4 6-2 Containment Air Locks.....................................

3/4 6-6 Internal Pressure......................................

3/4 6-8 Air Temperature......................................

3/4 6-9 DELETED 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS............................... 3/4 6-12 Containment Spray and Cooling Systems.....................................

3/4 6-12 DELETED 3/4.6.3 CONTAINMENT ISOLATION VALVES.....................................

3/4 6-15 Containment Ventilation System.....................................

3/4 6-19 3/4.6.4 COMBUSTIBLE GAS CONTROL............

......................... 3/4 6-20 DELETED DELETED DELETED Post-Incident Recirculation Systems.............

......................... 3/4 6-24 3/4.6.5 SECONDARY CONTAINMENT..........

........................... 3/4 6-25 Enclosure Building Filtration System.............

........................ 3/4 6-25 Enclosure Building.....................................

3/4 6-28 MILLSTONE - UNIT 2 VII Amendment No. 4-04, 453, 8, 24-I, 2, 78,

CONTAINMENT SYSTEMS 3/4.6.4 COMBUSTIBLE GAS CONTROL DELETED MILLSTONE - UNIT 2 3/4 6-20 Amendment No. 420,

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 2 3/4 6-21 Amendment No.

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 2 3/4 6-22 Amendment No.

-D Mark-Up and Proposed Bases (For Information Only)

DNC Millstone Power Station Unit 2

,.CONTAINMENT SYSTEMS (April 12, 1.999w)

BASES 3/4.6.4 COMBUSTIBLE GAS CONTROL The OPERABILITY of the equipment and systems required for the detection and kontrol of hydrogen gas ensures that this equipment will be ava iebTe aintain the hydrogen concentrat on within containment helow it, flammahl limit du9Lnn post-LOCA conditions.

Either recombiner unit is capable of controlling the expected hydrogen generation associated with l) zirconium-b water reactions, 2) radiolytic decomposition of water, and 3) corrosion ofVi metals within containment. This hydrogen control system is consistent with

/

the recommendations of Regulatory Guide 1.7, "Control of Combustible Gas Concentrations in Containment Following a LOCA."

The post-incident recirculation systems are provided to ensure adequate mixing of the-containment atmosphere following a LOCA.

This mixing action will prevent localized accumulations of hydrogen from exceeding the flammable limit.

MILLSTONE - UNIT 2 B 3/4 6-4 Amendment No.-243e-

CONTAINMENT SYSTEMS BASES 3/4.6.4 COMBUSTIBLE GAS CONTROL The OPERABILITY of the equipment and systems required for control of hydrogen gas I

ensures that this equipment will be available to maintain the hydrogen concentration within containment below its flammable limit during post-LOCA conditions.

I The post-incident recirculation systems are provided to ensure adequate mixing of the containment atmosphere following a LOCA. This mixing action will prevent localized accumulations of hydrogen from exceeding the flammable limit.

MILLSTONE - UNIT 2 B 314 6-4 Amendment No. 5233,

MILLSTONE POWER STATION UNIT 3 Technical Specifications Change Request Hydrogen Recombiners and Monitors -A -B -C -D Description and Assessment Mark-Up of Technical Specifications Proposed Technical Specifications Mark-Up and Proposed Bases

-A Description and Assessment DNC Millstone Power Station Unit 3

DESCRIPTION AND ASSESSMENT

1.0 INTRODUCTION

The proposed License amendment deletes Technical Specification (TS) 3/4.6.4.1, "Combustible Gas Control, Hydrogen Monitors", TS 3/4.6.4.2, "Electric Hydrogen Recombiners - W", references to the containment hydrogen monitors in TS 3.3.3.6.d and the containment hydrogen monitor surveillance requirement (SR) 4.3.3.6.2. 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 recombiners and hydrogen monitors resulted in numbering and formatting changes to other TS, which were otherwise unaffected by this proposed amendment.

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

2.0 DESCRIPTION

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

TS 3.3.3.6.d Accident Monitoring Instrumentation, Hydrogen Monitors Deleted SR 4.3.3.6.2 Accident Monitoring Instrumentation, Hydrogen Monitors Deleted Table 3.3-10 Item 18, Containment Hydrogen Monitor Deleted Table 4.3-7 Item 18, Containment Hydrogen Monitor Deleted TS 3/4.6.4.1 Combustible Gas Control, Hydrogen Monitors Deleted TS 3/4.6.4.2 Combustible Gas Control, Electric Hydrogen Recombiners Deleted Other TS changes included in this application are limited to renumbering and formatting changes that resulted directly from the deletion of the above requirements related to hydrogen recombiners and hydrogen monitors.

As described in NRC-approved Revision 1 of TSTF-447, the changes to TS requirements and associated renumbering of other TSs results in changes to various TS Bases sections. The associated Bases changes are attached for your information. The TS Bases changes will be submitted with a future update in accordance with TS 6.18,

'Technical Specifications (TS) Bases Control Program."

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.

5.0 TECHNICAL ANALYSIS

Dominion Nuclear Connecticut, Inc. (DNC) has reviewed the safety evaluation (SE) published September 25, 2003 (68 FR 55416) as part of the CLIIP Notice of Availability.

This verification included a review of the NRC staffs SE, as well as the supporting information provided to support TSTF-447. DNC has concluded that the justifications presented in the TSTF proposal and the SE prepared by the NRC staff are applicable to Millstone Unit 3 and justify this amendment for the incorporation of the changes to the Millstone Unit 3 TS.

6.0 REGULATORY ANALYSIS

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

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, DNC is making the following verifications and regulatory commitments:

1. DNC has verified that a hydrogen monitoring system capable of diagnosing beyond design-basis accidents is installed at Millstone Unit 3 and is making a regulatory commitment to maintain that capability. The hydrogen monitors will be included in the Millstone Unit 3 Technical Requirements Manual. This regulatory commitment will be implemented with the proposed amendment implementation.

2. Millstone Unit 3 does not have an inerted containment.

3. The commitments made by this letter supersede the previous commitments made in support of addressing NUREG-0737 requirements associated with Hydrogen Monitors and Hydrogen Recombiners.

7.0 NO SIGNIFICANT HAZARDS CONSIDERATION DNC has reviewed the proposed no significant hazards consideration determination published on September 25, 2003 (68 FR 55416) as part of the CLIIP. DNC has concluded that the proposed determination presented in the notice is applicable to Millstone Unit 3 and the determination is hereby incorporated by reference to satisfy the requirements of 10 CFR 50.91 (a).

8.0 ENVIRONMENTAL EVALUATION DNC has reviewed the environmental evaluation included in the model SE published on September 25, 2003 (68 FR 55416) as part of the CLIIP. DNC has concluded that the staffs findings presented in that evaluation are applicable to Millstone Unit 3 and the evaluation is hereby incorporated by reference for this application.

9.0 PRECEDENT This application is being made in accordance with the CLIIP. DNC is proposing TS changes consistent with TSTF-447 and the NRC staffs model SE published on September 25, 2003 (68 FR 55416). Millstone's TS are worded slightly different than the TSTF example but the information intended to be deleted is the same.

10.0 REFERENCES

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

-B Mark-Up of Technical Specifications DNC Millstone Power Station Unit 3

M-0-mh-t" r I n Inn INDEX;*

LIMG CONDITIOA£4S F(

OPERATION AiD iURVILL;ANCE -AJTJIEJ

'.NTS SECTION Mai Air Temperature 3/4 6-9 Containment Structural Integrity........................

3/4 6-10 Containment Ventilation System.......................

3/4 6-11 3/4.6.2 DEPRESSURIZAMO1N.ANICOOLNGSYSTEMS C ontialin ctud Spray System'.............................................

Containment r....'tei3/4 6-12 Recirculation Spray System 3/4 6-13 3/4.6.3 CONTAINMENT ISOLATION VALVES.............................

3/4 6-15.

3/4.6.4 GGUS~E-G AS GON4RGLL eLerE ly o

e N]

nt t

........1-U-L Eloctric Hydrcgen Roeeembinero 34..

6 17 3/4.6.5 SUBATMOSPHERIC PRESSURE CONTROL SYSTEM Steam Jet Air Ejector..........

3/4 6-18 3/4.6.6 SECONDARY CONTAINMENT Supplementary Leak Collection and Release System...

.3/4 6-19 Secondary Containment...............

3/4 6-22 Secondary Containment

'Structural Integrity.............

.;.;.;.;.;.;:.3/4 6-23

-314.7 PAANT SYSTEMS 3/4.7.1 TURBINE CYCLE Safety Valves.....

.3/4 7-1 TABLE 3.7-1 MAXIMUM ALLOWABLE POWER RANGE NEUTRON FLUXKHIGH SETPOINT WITH INOPERABLE STEAM LINE SAFETY VALVES....... 3/4 7-2 TABLE 3.7-2 DELETED..................

3/4 7-2 MILLSTONE -JUNT 3

ix Amendment No. 9, 400,,

4 44, +26, 27 r

INSTRUMENTATION ACCIDENT M0NITOR7NG INSTRUMENTATION LIMITING CONDITINO FOR OPERATION 3.3.3.6 The accident monitoring instrumentation channels shown in Table 3.3-10 shall be OPERABLE.

APPLICABILITY:

MODES I, 2, and 3.

AC-TI

-a.

With the number of OPERABLE accident monitoring instrumentation channels except the containment area high range radiation monitor, the containment hydrogen monitor, and reactor vessel water level, less than the Total Number of Channels shown in Table 3.3-10, restore the. inoperable channel(s) to OPERABLE status within 7 days, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

b. With the number of OPERABLE accident monitoring Instrumentation channels except the containment area-high range radiation monitor, the containment hydrogen monitor, and reactor vessel water level less than the minimum Channels OPERABLE requirements of Table 3.3-10, restore the inoperable channel(s) to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

c. With the number of OPERABLE channels for the containment area-high range radiation monitor less than required by either the tptal or the Minimum Channels OPERABLE requirements, initiate an alternate method of monitoring the appropriate parameter(s), within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and either restore the inoperable channel(s) to OPERABLE status within 7 days or prepare and submit a Special Report to the Commis-sion, pursuant to Specification 6.9.2, within 14 days that provides actions taken, cause of the inoperability, and the plans and sched-ule for restoring the channels to OPERABLE status.

e ro OPERABLE channels for the containment hydr wn~oil-4&s tanthe total number of channels _hf-i Tal

.- 1; sse the inoperable channel. t _~RBE status within 3D days or be n-tleast HOT STANDBY*f~ th et 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOW in t owing 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . With the number of operable channels ntainment hydrogen monitors less than the minimum c s OPERABLE r e nt of Table 3.3-10, restore the ino e

channel(s) to OPERABLE sta Ithfn 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in east HOT STANDBY within the inext 6 ho in at 1

aT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

e. With the number of OPERABLE channels for the reactor vessel water level monitor less than the Total number of Channels shown in Table 3.3-10, either restore the inoperable channel to OPERABLE status within 7 days if repairs are feasible without shutting down or prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 30 days following the event outlining the MILLSTONE - UNIT 3 3/4 3-59 Amendment No. f7, ;7A7 r

1X LIMITING CONDITION FOR OPERATION (Continued) action taken, the cause of the inoperability, and the plans and schedule for restoring the channel to OPERABLE status.

f. With the number of OPERABLE channels for the reactor vessel water level monitor less than the minimum channels OPERABLE requirements of Table 3.3-10, either restore the inoperable channel(s) to OPER-ABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months if repairs are feasible without shutting down or:

I. Initiate an alternate method of monitoring the reactor vessel inventory;

2. Prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 30 days following the event outlining the action taken, the cause of the inoperability, and the plans and schedule for restoring the channel(s) to OPERABLE status; and

3. Restore the channel(s) to OPERABLE status at the next scheduled refueling.

9. Entry into an OPERATIONAL NODE is permitted while subject to these ACTION requirements.

SURVEILLANCE REQUIREMENTS 4.3.3.6.1 Each accident monitoring instrumentation channel shall be demon-strated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION at the frequencies shown in Table 4.3-7.

{~s--e--6sh~xpuu ~ontor hal alo be demonstrate OPERBFb lyhn~

Sensor alibraton TESTat least oc e 9/33L. z, nasGGRDTS BASIS. _ _

t3, S

L D

Ct/

MILLSTONE - UNIT 3 W4e 3/4 3;59&

Amendment No. *7, 77, 7F,442,

TABLE 3.3-10 {Continued)

ACCIDENT MONITORING INSTRUMENTATION TOTAL NO. OF CHANNELS INSTRUMENT

16. Containment Area

High Range Radiation Monitor MINIMUM CHANNELS OPERABLE 1

.2

17. Reactor Vessel Water Level

18.

containmnt Hydrogen Maniao.

2*

1*

1Y l

19. Neutron Flux 2

1 to

A channel consists of eight sensors in a probe. A channel is operable if four or more sensors, half or more in 1-the upper head region and half or more in the upper plenum region, are operable.

cC 7

L

TABLE 4.3-7 (Continued)

ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS INSTRUMENT CHANNEL SCHECK CHANNEL CALIBRATIN

16.

Containment Area - High Range Radiation Monitor M

17.

Reactor Vessel Water Level Z(:'De7P,, +,_-

JD M

18.

Fnnt1ntnnt Ii1rnrtn I¶nnlnr

Ii lsv iu

19.

Neutron Flux M

CHANNEL CALIBRATION may consist of an electronic-calibration of the channel, not including the detector, 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.

- Electronic calibration from the ICC cabinets only.

f 2

0 0o

jane 24,i997S--

I "CONTAINMENT SYSTEMS 3M0COMBUSTIL A CONRO HYDmill MONITORS.

LIvMITNG CONVTION FOR OPERATON'

1 4.....

3.6.4.1 Two independ containment hydrogen monitors shall be OPERABLE APPLICABI2ITY-:MODE

2;nd 3; ACTION

a.: -

With one.hydrogen mo tor inoperable, restore th operable monitor to OPERABLE status withini 30 daysobna leig HOT.

wl4DYoithin the' next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWNwi the foll

b.

With both hydrogen monitors in o

,restore at least one monitor to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at OT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at A east HOT-SHUTDOWN withinei, n 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ;.

c.,

Entry into an OPERION MOD is

tted while subject to these ACTION requirements.

\\:-

SURVELLANCE PEQ 4.6.4.1 Each hydrogen monito II be demonstrated OPERABLE:

a.

By the ormnce of a CHANNEL CHBCK at least once per oursand

b.

By perfornance of a Hydrogen Sensor Calibration and an AN CHANNEL 0

RA:IONAL TEST at least once per 92 days on a STAGGERBD BASIS, and c

By the performance of a CALIBRATION at least once each ING INTERVAL.

~~~.

.iAA iLAFL

1Tr r''

j

&htIOMAA)

)

MILLSTONE - UNIT 3' 3/4'61.6 Amendment No. 47, 4, 4h,4'4i-

Iflh-ATUUMMr lT CVt~rrU

%tUI1 IIinnlu' l

3135 E1

\\

OIU17 s

AnAVJ EL TRIC HYDROGEN RECOMBINERS LIMITI CONDITION FOR OPERATION 3.6;4.2 Tw independent Hydrogen Recombiner Systems shall beOP ABLE.

APPLICABILITY:

ODES 1 and 2.

ACTION:

With one Hydrogen Reco iner System inoperable, restore he inoperable system to OPERABLE status withi 30 days or be in at least HO STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

SURVEILLANCE REQUIREMENTS 4.6.4.2 Each Hydrogen Recombiner ystem shal be demonstrated OPERABLE at least once per 24 months by:

a. Deleted

b.

Performing a CHANNEL CALIB I

f all recombiner instrumentation and control circuits,

c. Verifying through a vsual examinati that there is no evidence of abnormal conditions within the recom iner enclosure (i.e., loose wiring or struct al connections, depo its of foreign materials, etc.),

d. Verifying th integrity of all heater e ctrical circuits by performing resistance to ground test followi the above required functiona test. The resistance to ground for an heater phase shall be grea r than 10,000 ohms, and

e. Veri ing during a recombiner system functional test us g containment at spheric air at an acceptable flow rate as determin in Section 4.4.2.f that the gas temperature increases to greater t n or equal o 1100I F within 5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months and is maintained for at least 4 urs.

f Verifying during a recombiner system functional test using cont nment atmospheric air that the blower would be capable of deliverin at least 41.52 scfm at containment conditions of 12.47 psia and 130 T~h's pt induce--I~i~

-&P okAh MILLSTONE - UNIT 3 3/4 6-17 Amendment No. 97, PI, lop$ 177, 4e6>

-C Proposed Technical Specifications DNC Millstone Power Station Unit 3

INDEX LIMiTING CONDITIONS FOR OPERATION AND SURVEILLANCE REQUIREMENTS SECTION 3/4.6.2 3/4.6.3 314.6.4 314.6.5 314.6.6 3/4.7 PLANT 3/4.7.1 TABLE 3.7-1 TABLE 3.7-2 PAGE Air Temperature...............................................

3/4 6-9 Containment Structural Integrity...............................................

3/4 6-10 Containment Ventilation System...............................................

3/4 6-11 DEPRESSURIZATION AND COOLING SYSTEMS Containment Quench Spray System...............................................

3/4 6-12 Recirculation Spray System...............................................

3/4 6-13 CONTAINMENT ISOLATION VALVES...............................................

3/4 6-15 DELETED SUBATMOSPHERIC PRESSURE CONTROL SYSTEM Steam Jet Air Ejector...............................................

3/4 6-18 SECONDARY CONTAINMENT Supplementary Leak Collection and Release System................................ 3/4 6-19 Secondary Containment...............................................

314 6-22 Secondary Containment Structural Integrity...............................................

3/4 6-23 SYSTEMS TURBINE CYCLE Safety Valves...............................................

314 7-1 MAXIMUM ALLOWABLE POWER RANGE NEUTRON FLUX HIGH SETPOINT WITH INOPERABLE STEAM LINE SAFETY VALVES....... 3/4 7-2 DELETED...............................................

3/4 7-2 I

MILLSTONE - UNIT 3 ix Amendment No. 5, 6;, 8;, 99, 400,

444,

.46,217,

INSTRUMENTATION ACCIDENT MONITORING INSTRUMENTATION LIMITING CONDITION FOR OPERATION 3.3.3.6 The accident monitoring instrumentation channels shown in Table 3.3-10 shall be OPERABLE.

APPLICABILIY MODES 1, 2, and 3.

ACION:

a.

With the number of OPERABLE accident monitoring instrumentation channels except the containment area high range radiation monitor, and reactor vessel water level, less than the Total Number of Channels shown in Table 3.3-10, restore the inoperable channel(s) to OPERABLE status within 7 days, or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

b.

With the number of OPERABLE accident monitoring instrumentation channels except the containment area-high range radiation monitor, and reactor vessel water level less than the Minimum Channels OPERABLE requirements of Table 3.3-10, restore the inoperable channel(s) to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in at least HOT SHUTDOWN within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

c.

With the number of OPERABLE channels for the containment area-high range radiation monitor less than required by either the total or the Minimum Channels OPERABLE requirements, initiate an alternate method of monitoring the appropriate paramneter(s), within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , and either restore the inoperable channel(s) to OPERABLE status within 7 days or prepare and submit a Special Report to the Commission, pursuant to Specification 6.9.2, within 14 days that provides actions taken, cause of the inoperability, and the plans and schedule for restoring the channels to OPERABLE status.

d.

Deleted

e.

With the number of OPERABLE channels for the reactor vessel water level monitor less than the Total number of Channels shown in Table 3.3-10, either restore the inoperable channel to OPERABLE status within 7 days if repairs are feasible without shutting down or prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 30 days following the event outlining the MILLSTONE - UNIT 3 3/4 3-59 Amendment No. 47, 5, i6,

LIMITING CONDITION FOR OPERATION (Continued) action taken, the cause of the inoperability, and the plans and schedule for restoring the channel to OPERABLE status.

f.

With the number of OPERABLE channels for the reactor vessel water level monitor less than the minimum channels OPERABLE requirements of Table 3.3-10, either restore the inoperable channel(s) to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months if repairs are feasible without shutting down or:

1.

Initiate an alternate method of monitoring the reactor vessel inventory;

2.

Prepare and submit a Special Report to the Commission pursuant to Specification 6.9.2 within 30 days following the event outlining the action taken, the cause of the inoperability, and the plans and schedule for restoring the channel(s) to OPERABLE status; and

3.

Restore the channel(s) to OPERABLE status at the next scheduled refueling.

g.

Entry into an OPERATIONAL MODE is permitted while subject to these ACTION requirements.

SURVEILLANCE REQUIREMENTS 4.3.3.6.1 Each accident monitoring instrumentation channel shall be demonstrated OPERABLE by performance of the CHANNEL CHECK and CHANNEL CALIBRATION at the frequencies shown in Table 4.3-7.

4.3.3.6.2 Deleted MILLSTONE - UNIT 3 3/4 3-59a Amendment No. 47, W, i6, 442,

0z LIJ TABLE 3.3-10 (ContinueIL INSTRUMENT

16.

Containment Area - High Range Radiation Monitor

17.

Reactor Vessel Water Level

18.

Deleted

19.

Neutron Flux TOTAL NO. OF CHANNELS 2

2*

MINIMUM CHANNELS OPERABLE 1

1*

I 2

1 A channel consists of eight sensors in a probe. A channel is operable if four or more sensors, half or more in the upper head region and half or more in the upper plenum region, are operable.

!4 0

0 I

U)

TABLE 4.3-7 (Continued)

ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REOUIREMENTS INSTRUMENT

16.

Containment Area - High Range Radiation Monitor

17.

Reactor Vessel Water Level

18.

Deleted

19.

Neutron Flux CHANNEL CHECK M

M CHANNEL CALIBRATION R*

I M

R U) 0%.

U)

CHANNEL CALIBRATION may consist of an electronic calibration of the channel, not including the detector, 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.

- Electronic calibration from the ICC cabinets only.

z P

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNrr 3 3/4 6-16 Amendment No. 47, 4, a4, 4a4,

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 314 6-17 Amendment No.47,63,400,42, 1

O6,

-D Mark-Up and Proposed Bases (For Information Only)

DNC Millstone Power Station Unit 3

HwuE JEX

DccLlItL 18, 2003

BASES TABLE B3/4.4-1 REACTOR VESSEL FRACTURE TOUGHNESS PROPBRTIES'................B 3/4 4-9 FIGURE B 3/4.4-1 FAST NEUTRON FLUENCE(E>lMeV) ASA FUNCTION OF FULL POWER SERVICE LIFE B 3/4 4-10 3/4.4.10 DELETED.............

.B 3/4 4-15 3/4.4.11 D3ELETED............

B 3/4 4-15 3/4.5 ZMERGENCYCOR13COQLING SYSTE!MS, 3/4.5.1 ACCUMULATORS............................... ;.;: .:

B 3/4 54-1 3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS............................. !.;..;

B 3/4 5-1 3/4.5.4 REFUELING WATER STORAGE TANK...............................

.;.;B 3/4 5-2 3/4.5.5 pH TRISODIUM PHOSPHATE STORAGE BASKETS.......................................

..... B 3/4 5-3 3/4.6 CONTAINMENT SYSTEMS 314.6.1 PRIMARY CONTAINMENT B 3/4 6-1 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS B 3/4 6-2 3/4.63 CONTAINMENT ISOLATION VALVES........................................

3/4 6-3 3/4.6A4 C3IfflU3JTILE CAS CONTR(OL

.13.................

3/4 6 3ts 31.6A e vju ~ LE E A 3/4.6.5 SUBATMOSPHERIC PRESSURE CONTROL SYSTEM ;

...B 3/4 6-3d 3/4.6.6 SECONDARY CONTAINMENT B 3/4 6-4 I

i.-

3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE.B 3/4 7-1 3/4.7.2 DELETED..............................................

B 3/4 7-7:

3/4.7.3 REACTOR PLANT COMPONENT COOLING WAER SYSTEM............................. B 3/4 7-7 314.7.4 SERVICE WATER SYSTEM..

B 3/4 7-7.

3/4.7.5 UI.TIMftE IlEA SINK.............................................

..... B 3/4 7-8 3/4.7.6 DELETED......

B 3/4 7-10 3/4.7.7 CONTROL ROOM EMERGENCY VENTILATION SYSTEM......

B 3/4 7-10 3/4.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM.....

B 3/4 7-17 3/4.7.9 AUXILIARY BUILDING FILTER SYSTEM.....

B 3/4 7-23 3/4.7.10 SNUBBERS....................................................

B 3/4 7-23 MILLSTONED - UN1T 3 xiv Amendment No.48,9,145,449,436,2404,267,

-244,246,LDDCR03-Iv1P1-OO

INSTRUMENTATION BASES 3/4.3.3.6 ACCIDENT MONITORING INSTRUMENTATION (Continued)

A channel is operable if four or more sensors, half or more in the upper head region and half or more in the upper plenum region, are OPERABLE.

In the event more than four sensors in a Reactor Vessel Level channel are inoperable, repairs may only be possible during the next refueling outage. This is because the sensors are accessible only after the missile shield and reactor vessel head are removed. It is not feasible to repair a channel except during a refueling outage when the missile shield and reactor vessel head are removed to refuel the core. If only one channel is inoperable, it should be restored to OPERABLE status in a refueling outage as soon as reasonably possible. If both channels are inoperable, at least one channel shall be restored to OPERABLE.status in the nearest refueling outage.

The Reactor Coolant System Subcooling Margin Monitor, Core Exit Thermocouples, and Reactor Vessel Water Level instruments are processed by two separate trains of ICC (Inadequate Core Cooling) and HJTC (Heated Junction ThermoCouple) processors. The preferred indication for these parameters is the Safety Parameter Display System (SPDS) via the non-qualified PPC (Plant Process Computer) but qualified indication is provided in the instrument rack room. When the PPC data links cease to transmit data, the processors must be reset in order to restore the flow of data to the PPC. During reset, the qualified indication in the instrument rack room is lost. These instruments are OPERABLE during this reset since the indication is only briefly interrupted while the processors reset and the indication is promptly restored. The sensors are not removed from service during this reset. The train should be considered inoperable only if the qualified indication fails.to be restored following reset. Except for the non-qualified PPC display, the instruments operate as required.

drogen Monitors are provided to detect high hydrogen concentration conditio represent a ponairunment breach from a hydrogen explosion. Cent hydrogen concentration is also impo fying the adequacy of ml aons. The requirement to perform a hydrogen sensor calibratt 2 days is based upon vendor recommendations to maintain sensor c

n.

tion consists of a two point calibration, utilizing gas cpgapproximately one percent s for one of the calibration o gas containing approximately four percent hydrogen gher C

on t

point.

3/4.3.3.7 Deleted.

3/4.3.3.8 DELETED 3/4.3.3.9 DELETED 3/4.3.3.10 DELETED 3/4.3.4 DELETED MILLSTONE - UNIT 3 B 3/4 3-6 Amendment No. 4i-8, 4-9, I2,

2eM,200`

CONTAINMENT SYSIEM BASES

t..

YFor the purposes of meeting this LC0, neither the bontainment isolation valve, nor any alternate valve on a closed'system have a leakage limit associated with valve operability.

The opening of containment isolation valves onan intermiittent basis under administrative controls includes the following considerations: (1) stationing an operator,- Whod is in constant communication with.

the control room, at the valve controls, (2) iintructing this operator to close these valves in an accident situation, and (3) asuring that environmental conditions wilinot preclude access to close the valves and that this action will prevent the release of radioactivity outside the containment.

. he appropriate administrative controls; based on the above considerations, to allow containment isolation valves tobe opened are contained in the procedures that will be used to operate the valves. Entries' should,be placed in the Shift Manager Log when these valves are opened or closed. However, it is not necessary to lo'ginto any Technical Specification Action Statement for these valves, provided the appropriate administrative controls have been established.

'Opeing a closed containment isolation valve bypasse a plant design feature that prevents the release of radioactivity outside the containmenLTherefore,this should not be done frequently, and the time the valve is opened should be minimized. The detbrmhiation of the appropriate adminstative controls for containment isolation valves requires an evaluation of the expected environmental conditioni This evaluation must conclude environmental conditions will not preclude access to close the valve, and this action will prevent the release of radioactivity outside of containment through.the respective penetration.

When the Residual Heat Removal (RHR) System is placed in service in the plant cooldown mode of operation, the RHR suction isolation remotely operated valves 3RHS*MV870IA and 3RHS*MV8701B, and/or 3RHS*MV8702A and 3RHS*MV8702B are opened. These valves are normally.

operated 'fr6nithe control room. They do not receive an automatic containment isolation closure signal, but are interlocked to prevent their opening if Reactor Coolant System (RCS) pressure is greater than approximately 412.5 psia. When any of these valves are opened, either one of the two required licensed (Reactor Operator) control room operators can be credited as the operator'rquired for administrative controL It is not necessary to use a separate dedicated operator.

I 2L4_"

CMB 12STIBLB GAS CONTROL

{. Hydrogen Mo rovided to detect high hydrogen conc itions that represent a!

potential for containment breac gen explosion.

ent hydrogen concentration is also important in verifying the adequacy of mitiga i

e requirement to perform a hydrogen sensor

' calibration at least every 92 to maintain sensor calibration This calibration consists point calibration, utilizing gas-con

-imtely one percent bhydrogen eof the calibration points, and gas containing approximately.

ydrogen goffier calibration point.

I AIIIISTONE - UNIT 3 -

B 3/4 63a Amendment No. 28,'S,6,4 +42

-F hb!- AI1w11VIM 1 4

I 0 1

a InIIL BAWkS

/

3/4.6.4 tB~USTBLE GAS CONTROL (Continued)

^..

The ERABILITY of the equipment and systems required for the detection and con of hydrogen gas en es that this equipment will be available to maintain the hydrogen concen tion within containment bob its flammable limit during post-LOCA conditions. Either recombiner t or the Mechanical Vacuum ps are capable of controlling the expected hydrogen generation ssociated with:

(1) zirconium-water re otions, (2) radiolytic decomposition of water, and (3) corrosion fmetals within containment. These Hydogen Control Systems are consistent with the recommendations of Regulatory Guide 1.7, "Control of Co bustible Gas Concentrations in Containment Followin a LOCA" March 1971.

-The Post.LOe.A s

th a iydr g n bitbl0wers hased on a series 6f equations supplied by the blower iifacturer. These equations are also i basis of the acceptance criteria used in the surveillance pro ure. The required performance w basedon startng containment conditions before the LOCA of 1059p a (total pressure), 120OF and OO%'relatv hid1y; The surveillance procedure shall the following meth to verify acceptable blower flow rate:

1.

Definitions and constants CFM = cubic feet per minute RPM = revolutions per minute Blower RPM = 3550 Blower f13/revolution =.028 f 3

/

Standard CFM = gas volumeI nvertel to conditions of 680F d 14.7 psia.

2.

Measure and record the fo owing information:

Pcontainment-Avera of3LMS*P934, 935, 936, and 937 (psia)

Pout-From 3HCS 1A or B (psia)

Tc-Containmit temperature (OF)

Pin-M e with a new inlet gauge oi calculate from Equation 3a below (psia) scfm easured-See Procedure/Form 3613A.3-1 f-From Table 2 (psi)

/ A-As found Slip Constant Accuracy-Instrument accuracy range from Table 1.

M] N -e uiT e

B rc 3/4 a

Alendmen N.

{e MMISTO)NE - UNIT 3 B 3/4 6-3b Amendment No. 28. A. 4,

,-4 I I I

1

11.CNTA1NMENT SYSTEMS

\\SES..

D embe'r18, 2 003 I.

314AA COMBUSTIBLE GAS CONTOL (Continued).

3.

jIculate as found slp constant (i a;.'

Pin =Pcontainment -APf

.b.\\

easured-AccuracY]

. 14 7T T 6

0.028 x 0.95 j

Pin 28 J..

-X-.14iiv-UT

.x(piE

~9 In, Pin

4.

Clii flow rate using Acalcul3ed Step 3.

a.

Slip RPM A x (4.937)1/2'x 1.

/

I

b.

Actual Inlet CFM N

ACFM =.028 (3550 - Slip RPI

c.

Standard CFM scfin = ACFM 0.725

d.

Postaccident scfm Minimum

e.

Acceptance Flow Rate Postaccident scfm minim 4

sabfild scfm (me~~rd I

cacy Range to<50 6.98

5.81 X 60to<90

.5 Table 2 Inlet Piping Loss (Ref. 1) scfin Measured (Unadjusted)

&Pf (si) 30 40 50 60 70

.21

.31'

.52

.73

.98 1.28 80 4eD),A, jeal-MILLSTONE - UNiT 3 B 3/46-3c Amendment No. C3,442,

6, LBDCR 03-MP3-005

i SG~lulb F, 2003 CONTAINMENT SYSTEMS BASES

_ M 3

OMB3USTIBlLE! G AS CONTROL (Continued!)

References:

1. Calculai on.90 2

low Acceptance or3HCS*RBNR IA/B Blowers 3HCS*CIA/B.3 sCalcu9lati L

2 E, '"Hy biner Flow Error.Analysis?'.

The acceptance flow required flow rate at the worst case conditions 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the LOCA.

ysis assumes the recombiners are started no later than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ax ccident. The eillance shall verify the gas temperature and blower flow rate concurrently.

I 3/4.6.5 SUBATMOSPHERIC PRESSR CONTROL SYSTEM 3/4.6.5.1 STEAM JET AIR EACTOR The closure of the isolation valves in the suction of the steam jet air ejector ensures that: (1) the containment internal pressure may be maintained within its operation limits by the mechanical vacuum pumps, and (2) the containment atmosphere is isolated from the outside environment in the event of a LOCA. These valves are required to be closed for containment isolation.

MILLSTONE -UNIT 3 B 3/46-3d Amendment No. 6, 442,216

INDEX BASES SECTIONA TABLE B3/4.4-1 REACTORVESSEL FRACTURE TOUGHNESS PROPERTIES... B 3/4 4-9 FIGURE B 3/4.4-1 FAST NEUTRON FLUENCE (E>lMeV) AS A FUNCTION OF FULL POWER SERVICE LIFE........................................................... B 3/4 4-10 3/4.4.10 DELETED............................................................ B 3/4 4-15 3/4.4.11 DELETED..........................................................

B 3/4 4-15 3/4.5 EMERGENCY CORE COOLING SYSTEMS 3/4.5.1 ACCUMULATORS..........................................................

B 3/4 5-1 3/4.5.2 and 3/4.5.3 ECCS SUBSYSTEMS..........................................................................B 3/4 5-1 3/4.5.4 REFUELING WATER STORAGE TANK.................................................... B 3/4 5-2 314.5.5 pH TRISODIUM PHOSPHATE STORAGE BASKETS............................. B 3/4 5-3 3/4.6 CONTAINMENT SYSTEMS 3/4.6.1 PRIMARY CONTAINMENT.

B 314 6-1 3/4.6.2 DEPRESSURIZATION AND COOLING SYSTEMS.

B 3/4 6-2 3/4.6.3 CONTAINMENT ISOLATION VALVES.....................................................B 3/4 6-3 3/4.6.4 DELETED 3/4.6.5 SUBATMOSPHERIC PRESSURE CONTROL SYSTEM.

B 3/4 6-3d 3/4.6.6 SECONDARY CONTAINMENT................................................................B 3/4 64 3/4.7 PLANT SYSTEMS 3/4.7.1 TURBINE CYCLE B 3/4 7-1 3/4.7.2 DELETED.B 314 7-7 3/4.7.3 REACTOR PLANT COMPONENT COOLING WATER SYSTEM.

B 34 7-7 314.7.4 SERVICE WATER SYSTEM.B 3/4 7-7 3/4.7.5 ULTIMATE HEAT SINK.

B 3/4 7-8 3/4.7.6 DELETED..

B 3/4 7-10 3/4.7.7 CONTROL ROOM EMERGENCY VENTILATION SYSTEM.

B 3/4 7-10 3/4.7.8 CONTROL ROOM ENVELOPE PRESSURIZATION SYSTEM.

B 3/4 7-17 3/4.7.9 AUXILIARY BUILDING FILTER SYSTEM..

B 3/4 7-23 3/4.7.10 SNUBBERS.B 3/4 7-23 MILLSTONE - UNIT 3 xiv Amendment No. 48,89, 14., 449,436, 04, 2G, 244,246,

BASES 3/4.3.3.'6 ACCIDENT MONITORING INSTRUMENTATION (Continued)

A channel is operable if four or more sensors, half or more in the upper head region and half or more in the upper plenum region, are OPERABLE.

In the event more than four sensors in a Reactor Vessel Level channel are inoperable, repairs may only be possible during the next refueling outage. This is because the sensors are accessible only after the missile shield and reactor vessel head are removed. It is not feasible to repair a channel except during a refueling outage when the missile shield and reactor vessel head are removed to refuel the core. If only one channel is inoperable, it should be restored to OPERABLE status in a refueling outage as soon as reasonably possible. If both channels are inoperable, at least one channel shall be restored to OPERABLE status in the nearest refueling outage.

The Reactor Coolant System Subcooling Margin Monitor, Core Exit Thermocouples, and Reactor Vessel Water Level instruments are processed by two separate trains of ICC (Inadequate Core Cooling) and HJTC (Heated Junction ThermoCouple) processors. The preferred indication for these parameters is the Safety Parameter Display System (SPDS) via the non-qualified PPC (Plant Process Computer) but qualified indication is provided in the instrument rack room. When the PPC data links cease to transmit data, the processors must be reset in order to restore the flow of data to the PPC. During reset, the qualified indication in the instrument rack room is lost. These instruments are OPERABLE during this reset since the indication is only briefly interrupted while the processors reset and the indication is promptly restored. The sensors are not removed from service during this reset. The train should be considered inoperable only if the qualified indication fails to be restored following reset. Except for the non-qualified PPC display, the instruments operate as required.

3/4.3.3.7 Deleted.

3/4.3.3.8 DELETED 3/4.3.3.9 DELETED 3/4.3.3.10 DELETED 314.3.4 DELETED MILLSTONE - UNIT 3 B 3/4 3-6 Amendment No. 488, 419-9,

CONTAINMENT SYSTEMS BASES For the purposes of meeting this LCO, neither the containment isolation valve, nor any alternate valve on a closed system have a leakage limit associated with valve operability.

The opening of containment isolation valves on an intermittent basis under administrative controls includes the following considerations: (1) stationing an operator, who is in constant communication with the control room, at the valve controls, (2) instructing this operator to close these valves in an accident situation, and (3) asuring that environmental conditions will not preclude access to close the valves and that this action will prevent the release of radioactivity outside the containment.

The appropriate administrative controls, based on the above considerations, to allow containment isolation valves to be opened are contained in the procedures that will be used to operate the valves. Entries should be placed in the Shift Manager Log when these valves arc opened or closed. However, it is not necessary to log into any Technical Specification Action Statement for these valves, provided the appropriate administrative controls have been established.

Opening a closed containment isolation valve bypasses a plant design feature that prevents the release of radioactivity outside the containment. Therefore, this should not be done frequently, and the time the valve is opened should be minimized. The determination of the appropriate administrative controls for containment isolation valves requires an evaluation of the expected environmental conditions. This evaluation must conclude environmental conditions will not preclude access to close the valve, and this action will prevent the release of radioactivity outside of containment through the respective penetration.

When the Residual Heat Removal (RHR) System is placed in service in the plant cooldown mode of operation, the RHR suction isolation remotely operated valves 3RHS*MV8701A and 3RHS*MV870IB, and/or 3RHS*MV8702A and 3RHS*MV8702B are opened. These valves are normally operated from the control room. They do not receive an automatic containment isolation closure signal, but are interlocked to prevent their opening if Reactor Coolant System (RCS) pressure is greater than approximately 412.5 psia. When any of these valves are opened, either one of the two required licensed (Reactor Operator) control room operators can be credited as the operator required for administrative control. It is not necessary to use a separate dedicated operator.

MILLSTONE - UNIT 3 B 3/4 6.3a Amendment No. 29, 6, 4A4, V*6,

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 B 3/4 63b Amendment No. 2, 63, 442,246,

THIS PAGE INTENTIONALLY LEFT BLANK MILLSTONE - UNIT 3 B 3/4 63c Amendment No. 63, i42, N-C6,

CONTAINMENT SYSTEMS BASES 3/4.6.5 SUBATMOSPHERIC PRESSURE CONTROL SYSTEM 314.6.5.1 STEAM JET AIR EJECTOR The closure of the isolation valves in the suction of the steam jet air ejector ensures that:

(1) the containment internal pressure may be maintained within its operation limits by the mechanical vacuum pumps, and (2) the containment atmosphere is isolated from the outside environment in the event of a LOCA. These valves are required to be closed for containment isolation.

MILLSTONE - UNIT 3 B 3/4 6-3d Amendment No. 6;, 44I, 2,

v t e Letter Sequence Request
TAC:MC4393, Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors (Open)
Initiation Request Acceptance... Administration Questions Answers Results Approval... Other: ML042520424, ML050840168, ML050900345
MONTHYEAR2004-09-08 [Table View]

ML042650363

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

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

References:

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