Text

License Amendment Request Applicable to Oconee Technical Specification 3.3.8, PAM Instrumentation, and 3.6.7, Hydrogen Recombiners, Using the Consolidated Line Item Improvement Process
	ML050810416
Person / Time
Site:	Oconee, McGuire, Mcguire
Issue date:	03/16/2005
From:	Morris J; Duke Power Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML050810416 (44)
	v • d • e

JAMES R MORRIS Duke Vice President, Nuclear Support r ~owere, Nuclear Generation Duke Power 526 South Church St.

March 16, 2005 Charlotte, NC 28202 Mailing Address:

EC07H I PO Box 1006 U. S. Nuclear Regulatory Commission Charlotte, NC 28201-1006 Washington, DC 20555-0001 704 382 6401 ATTENTION: Document Control Desk 704 382 6056 fax james.morris@duke-energy.com

SUBJECT:

Duke Energy Corporation Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 50-270, and 50-287 McGuire Nuclear Station, Units 1 and 2 Docket Nos. 50-369 and 50-370 License Amendment Request Applicable to Oconee Technical Specification 3.3.8, PAM Instrumentation; and McGuire Technical Specifications 3.3.3, PAM Instrumentation, and 3.6.7, Hydrogen Recombiners, Using the Consolidated Line Item Improvement Process (CLIIP)

In a letter dated September 20, 2004, Duke Energy Corporation (Duke) submitted a license amendment request (LAR) for the Oconee and McGuire Nuclear Stations Facility Operating Licenses and Technical Specifications (TS). This LAR applied to Oconee TS 3.3.8, PAM Instrumentation; and McGuire TS 3.3.3, PAM Instrumentation, and TS 3.6.7, Hydrogen Recombiners. The Bases for McGuire TS 3.6.8 and 3.6.9, as well as the Tables of Contents, were also affected by this LAR. The changes contained in this LAR implemented the NRC CLIIP TS improvement item published in the Federal Register on September 25, 2003 (68 FR 55416). This letter provides new reprinted TS pages for the NRC's use in issuing this LAR, which has now been approved.

Attachment 1 provides new reprinted pages for Oconee and Attachment 2 provides new reprinted pages for McGuire.

Inquiries on this matter should be directed to J. S. Warren at 704-875-5171.

Very truly yours, mes R. Morris www. dukepower. corn

U. S. Nuclear Regulatory Commission March 16, 2005 Page 2 xc w/Attachments:

W. D. Travers U. S. Nuclear Regulatory Commission Regional Administrator, Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, GA 30303 L. N. Olshan (Addressee Only)

NRC Senior Project Manager (ONS)

U. S. Nuclear Regulatory Commission Mail Stop 0-8 H12 Washington, DC 20555-0001 J. J. Shea (Addressee Only)

NRC Senior Project Manager (MNS)

U. S. Nuclear Regulatory Commission Mail Stop 0-8 H12 Washington, DC 20555-0001 M. C. Shannon Senior Resident Inspector (ONS)

U. S. Nuclear Regulatory Commission Oconee Nuclear Site J. B. Brady Senior Resident Inspector (MNS)

U. S. Nuclear Regulatory Commission McGuire Nuclear Site

U. S. Nuclear Regulatory Commission March 16, 2005 Page 3 James R. Morris affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.

Jam R. Morris Subscribed and sworn to me: 7

, f _

/ 16a, a_ - _

I)ate

(;p.2 Notary Public My commission expires: IZ- 7 Da Date SEAL

Attachment 1 Oconee Units 1, 2, and 3 Revised (Clean) Technical Specifications Pages Remove Insert 3.3.8-2 3 .3.8-2 3.3.8-3 3.3.8-3 3.3.8-4 3.3.8-4 3.3.8-5 3.3.8-5 B3.3.8-7 B3.3.8-7 B3.3.8-15 B3.3.8-15 B3.3.8-16 B3.3.8-16 B3.3.8-19 B3.3.8-19

PAM Instrumentation 3.3.8 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. --- NOTE-- C.1 Restore one channel to 7 days Not applicable to OPERABLE status.

Functions 14, 18, 19, 20 and 22.

One or more Functions with two required channels inoperable.

D. Not Used D.1 Not Used Not Used E. --- NOTE---- E.1 Restore required 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Only applicable to channel to OPERABLE Function 14. status.

One required channel inoperable.

(continued)

OCONEE UNITS 1,2, &3 3.3.8-2 Amendment Nos. XXX, XXX, & XXX I

PAM Instrumentation 3.3.8 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME F. -- NOTE---- F.1 Declare the affected Immediately Only applicable to train inoperable.

Functions 18, 19, 20, and 22.

One or more Functions with required channel inoperable.

G. Required Action and G.1 Enter the Condition Immediately associated Completion referenced in Time of Condition C or Table 3.3.8-1 for the I E not met. channel.

H. As required by H.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Required Action G.1 and referenced in AND Table 3.3.8-1.

H.2 Be in MODE 4. 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months I. As required by 1.1 Initiate action in Immediately Required Action G.1 accordance with and referenced in Specification 5.6.6.

Table 3.3.8-1.

OCONEE UNITS 1, 2,& 3 3.3.8-3 Amendment Nos. XXX, XXX, & XXX I

PAM Instrumentation 3.3.8 SURVEILLANCE REQUIREMENTS

NOTE------

These SRs apply to each PAM instrumentation Function in Table 3.3.8-1 except where indicated.

SURVEILLANCE FREQUENCY SR 3.3.8.1 Perform CHANNEL CHECK for each required 31 days instrumentation channel that is normally energized.

SR 3.3.8.2 NOTE---

Only applicable to PAM Functions 7 and 22.

Perform CHANNEL CALIBRATION. 12 months SR 3.3.8.3 --- NOTES--

1. Neutron detectors are excluded from CHANNEL CALIBRATION.

2. Not applicable to PAM Functions 7 and 22.

Perform CHANNEL CALIBRATION. 18 months OCONEE UNITS 1, 2, & 3 3.3.8-4 Amendment Nos. XXX, XXX & XXX I

PAM Instrumentation 3.3.8 Table 3.3.8-1 (page 1 of 1)

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

1. Wide Range Neutron Flux 2 H

2. RCS Hot Leg Temperature 2 H

3. RCS Hot Leg Level 2

4. RCS Pressure (Wide Range) 2 H

5. Reactor Vessel Head Level 2

6. Containment Sump Water Level (Wide Range) 2 H

7. Containment Pressure (Wide Range) 2 H

8. Containment Isolation Valve Position 2 per penetration flow path(OWXc) H

9. Containment Area Radiation (High Range) 2

10. Not Used I

11. Pressurizer Level 2 H

12. Steam Generator Water Level 2perSG H

13. Steam Generator Pressure 2perSG H

14. Borated Water Storage Tank Water Level 2 H

15. Upper Surge Tank Level 2 H

16. Core Exit Temperature 2 Independent sets of 5 (d) H

17. Subcooling Monitor 2 H

18. HPI System Flow 1 per train NA

19. LPI System Flow I per train NA

20. Reactor Building Spray Flow 1 per train NA

21. Emergency Feedwater Flow 2perSG H

22. Low Pressure Service Water Flow to LPI Coolers 1 per train NA (a) Not required for isolation valves whose associated penetration is Isolated by at least one dosed and deactivated automatic valve, dosed manual valve, blind flange, or check valve with flow through the valve secured.

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

(c) Position Indication requirements apply only to containment isolation valves that are electrically controlled.

(d) The subcooling margin monitor takes the average of the five highest CETs for each of the ICCM trains.

OCONEE UNITS 1, 2, & 3 3.3.8-5 Amendment Nos. XXX, XXX & XXX I

PAM Instrumentation B 3.3.8 BASES LCO 9. Containment Area Radiation (High Range)

(continued)

Containment Area Radiation (High Range) instrumentation is a Type C, Category 1 variable provided to monitor the potential for significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans. The Containment Area Radiation instrumentation consists of two channels (RIA 57 and 58) with readout on two indicators and one channel recorded. The indicated range is 1 to 107 R/hr.

10. Not Used

11. Pressurizer Level Pressurizer Level instrumentation is a Type A, Category I variable used in combination with other system parameters to determine whether to terminate safety injection (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. The Pressurizer Level instrumentation consists of two channels (Train A channel consisting of two indications and Train B channel consisting of one indication) with two channels indicated and one channel recorded.

(Note: two indications are available in Train A, but only one is required). The indicated range is 0 to 400 inches (11% to 84%

level as a percentage of volume).

OCONEE UNITS 1, 2, & 3 B 3.3.8-7 Amendment Nos. XXX, XXX, & XXX I

PAM Instrumentation B 3.3.8 BASES ACTIONS C.1 (continued) operation with two required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance of 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. Condition C is modified by a Note indicating this Condition is not applicable to PAM Functions 14, 18,19, 20, and 22.

D.1 Not Used.

E.1 When one required BWST water level channel is inoperable, Required Action E.1 requires the channel to be restored to OPERABLE status.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is based on the relatively low probability of an event requiring BWST water and the availability of the remaining BWST water level channel. Continuous operation with one of the two required channels inoperable is not acceptable because alternate indications are not available. This indication is crucial in determining when the water source for ECCS should be swapped from the BWST to the reactor building sump.

Condition E is modified by a Note indicating this Condition is only applicable to PAM Function 14.

F.1 When a flow instrument channel is inoperable, Required Action F.1 requires the affected HPI, LPI, or RBS train to be declared inoperable OCONEE UNITS 1, 2, & 3 B 3.3.8-15 Amendment Nos. XXX, XXX, & XXX I

PAM Instrumentation B 3.3.8 BASES ACTIONS F.1 (continued) and the requirements of LCO 3.5.2, LOC 3.5.3, or LCO 3.6.5 apply. For Function 22, LPSW flow to LPI coolers, the affected train is the associated LPI train. For Function 18, HPI flow, an inoperable flow instrument channel causes the affected HPI train's automatic function to be inoperable. The HPI train continues to be manually OPERABLE provided the HPI discharge crossover valves and associated flow instruments are OPERABLE. Therefore, HPI is in a condition where one HPI train is incapable of being automatically actuated but capable of being manually actuated. The required Completion Time for declaring the train(s) inoperable is immediately. Therefore, LCO 3.5.2, LCO 3.5.3, or LCO 3.6.5 is entered immediately, and the Required Actions in the LCOs apply without delay. This action is necessary since there is no alternate flow indication available and these flow indications are key in ensuring each train is capable of performing its function following an accident. HPI and LPI train OPERABILITY assumes that the associated PAM flow instrument is OPERABLE because this indication is used to throttle flow during an accident and assure runout limits are not exceeded or to ensure the associated pumps do not exceed NPSH requirements.

For Function 20, the RBS train associated with an inoperable RBS flow instrument must be declared inoperable even though it is no longer needed to support throttling flow because this action is required by Technical Specifications.

Condition F is modified by a Note indicating this Condition is only applicable to PAM Functions 18, 19, 20, and 22.

G.1 Required Action G.1 directs entry into the appropriate Condition referenced in Table 3.3.8-1. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met the Required Action and associated Completion Time of Condition C or E, as applicable, Condition G is entered for that channel and provides for transfer to the appropriate subsequent Condition.

OCONEE UNITS 1, 2, & 3 B 3.3.8-16 Amendment Nos. XXX, XXX, & XXX I

PAM Instrumentation B 3.3.8 BASES SURVEILLANCE SR 3.3.8.2 and SR 3.3.8.3 (continued)

REQUIREMENTS Note 1 to SR 3.3.8.3 clarifies that the neutron detectors are not required to be tested as part of the CHANNEL CALIBRATION. There is no adjustment that can be made to the detectors. Furthermore, adjustment of the detectors is unnecessary because they are passive devices, with minimal drift. Slow changes in detector sensitivity are compensated for by performing the daily calorimetric calibration and the monthly axial channel calibration.

For the Containment Area Radiation instrumentation, a CHANNEL CALIBRATION may consist of an electronic calibration of the channel, not including the detector, for range decades above 10 R/hr, and a one point calibration check of the detector below 10 R/hr with a gamma source.

Whenever a sensing element is replaced, the next required CHANNEL CALIBRATION of the resistance temperature detectors (RTD)sensors or Core Exit thermocouple sensors is accomplished by an inplace cross calibration that compares the other sensing elements with the recently installed sensing element.

SR 3.3.8.2 is modified by a Note indicating that it is applicable only to Functions 7 and 22. SR 3.3.8.3 is modified by Note 2 indicating that it is not applicable to Functions 7 and 22. The Frequency of each SR is based on operating experience and is justified by the assumption of the specified calibration interval in the determination of the magnitude of equipment drift.

REFERENCES 1. Duke Power Company letter from Hal B. Tucker to Harold M.

Denton (NRC) dated September 28, 1984.

2. UFSAR, Section 7.5.

3. NRC Letter from Helen N. Pastis to H. B. Tucker, "Emergency Response Capability - Conformance to Regulatory Guide 1.97,"

dated March 15,1988.

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

OCONEE UNITS 1, 2, & 3 B 3.3.8-19 Amendment Nos. XXX, XXX, & XXX I

Attachment 2 McGuire Units 1 and 2 Revised (Clean) Technical Specifications Pages Remove Insert ii ii 3.3.3-2 3.3 .3-2 3.3.3-3 3.3.3-3 3.3.3-4 3.3.3-4 3.6.7-1 3.6.7-1 ii ii B 3.3.3-1 thru B 3.3.3-15 B 3.3.3-1 thru B 3.3.3-14 B 3.6.7-1 thru B 3.6.7-5 B 3.6.7-1 3.6.8-1 thru B 3.6.8-5 B 3.6.8-1 thru B 3.6.8-5 3.6.9-1 thru B 3.6.9-5 B 3.6.9-1 thru B 3.6.9-5

TABLE OF CONTENTS (continued) 3.4 REACTOR COOLANT SYSTEM (RCS) (continued) 3.4.6 RCS Loops-MODE 4 ................................................... 3.4.6-1 3.4.7 . RCS Loops-MODE 5, Loops Filled ............................................... 3.4.7-1 3.4.8 RCS Loops-MODE 5, Loops Not Filled ......................................... 3.4.8-1 3.4.9 Pressurizer ................................................... 3.4.9-1 3.4.10 Pressurizer Safety Valves ................................................... 3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) ...................... 3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP) System ........... 3.4.12-1 3.4.13 RCS Operational LEAKAGE ................................................... 3.4.13-1 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage ................................. 3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation ........................................ 3.4.15-1 3.4.16 RCS Specific Activity ................................................... 3.4.16-1 3.4.17 RCS Loop-Test Exceptions ................................................... 3.4.17-1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) ............................. 3.5.1-1 3.5.1 Accumulators ................................................... 3.5.1-1 3.5.2 ECCS-Operating ................................................... 3.5.2-1 3.5.3 ECCS-Shutdown .................................................... 3.5.3-1 3.5.4 Refueling Water Storage Tank (RWST) .......................................... 3.5.4-1 3.5.5 Seal Injection Flow ................................................... 3.5.5-1 3.6 CONTAINMENT SYSTEMS .................................................... 3.6.1-1 3.6.1 Containment .................................................... 3.6.1-1 3.6.2 Containment Air Locks ................................................... 3.6.2-1 3.6.3 Containment Isolation Valves ................................................... 3.6.3-1 3.6.4 Containment Pressure ................................................... 3.6.4-1 3.6.5 Containment Air Temperature .................................................... 3.6.5-1 3.6.6 Containment Spray System .................................................... 3.6.6-1 3.6.7 Not Used ......

3.6.8 Hydrogen Skimmer System (HSS) ............................. 3.6.8-1 3.6.9 Hydrogen Mitigation System (HMS) .3.6.9-1 3.6.10 Annulus Ventilation System (AVS) .3.6.10-1 3.6.11 Air Return System (ARS). 3.6.11-1 3.6.12 Ice Bed. 3.6.12-1 3.6.13 Ice Condenser Doors .3.6.13-1 3.6.14 Divider Barrier Integrity .3.6.14-1 3.6.15 Containment Recirculation Drains .3.6.15-1 3.6.16 Reactor Building. 3.6.16-1 3.7 PLANT SYSTEMS .3.7.1-1 3.7.1 Main Steam Safety Valves (MSSVs) .3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs) .3.7.2-1 3.7.3 Main Feedwater Isolation Valves (MFIVs),

Main Feedwater Control Valves (MFCVs), MFCV's Bypass Valves and Main Feedwater (MFW) to Auxiliary Feedwater (AFW) Nozzle Bypass Valves (MFW/AFW NBVs). 3.7.3-1 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs) .3.7.4-1 McGuire Units 1 and 2 ii Amendment Nos.

PAM Instrumentation 3.3.3 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME E. One or more Functions E.1 Restore one channel to 7 days with two required OPERABLE status.

channels inoperable.

F. Not Used F.1 Not Used Not Used I G. Required Action and G.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition D or E AND I not met.

G.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months H. Required Action and H.1 Initiate action in Immediately associated Completion accordance with of Condition D not met. Specification 5.6.7.

McGuire Units 1 and 2 3.3.3-2 Amendment Nos.

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.

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 Not Used l SR 3.3.3.3 - - -_NOTE--

Neutron detectors are excluded from CHANNEL CALIBRATION.

Perform CHANNEL CALIBRATION. 18 months McGuire Units 1 and 2 3.3.3-3 Amendment Nos.

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

Post Accident Monitoring Instrumentation FUNCTION REQUIRED CHANNELS CONDITIONS

1. Neutron Flux (Wide Range) 2 BC,EG

2. Reactor Coolant System (RCS) Hot Leg Temperature 2 BC.E,G

3. RCS Cold Leg Temperature 2 BC,E.G

4. RCS Pressure (Wide Range) 2 B.CE,G

5. Reactor Vessel Water Level (Dynamic Head Range) 2 B,CE,G

6. Reactor Vessel Water Level (Lower Range) 2 BC.E.G

7. Containment Sump Water Level (Wide Range) 2 BC.E.G

8. Containment Pressure (Wide Range) 2 B,CEG

9. Containment Atmosphere Radiation (High Range) I DH

10. Not Used Not Used Not Used I

11. Pressurizer Level 2 BCE.G

12. Steam Generator Water Level (Narrow Range) 2 per steam generator B,CEG

13. Core Exit Temperature - Quadrant 1 B.C.E.G 2 (a)

14. Core Exit Temperature - Quadrant 2 B.CE.G 2 (a)

15. Core Exit Temperature - Quadrant 3 BC,E,G 2 (a)

16. Core Exit Temperature - Quadrant 4 BC,E,G 2 (a)

17. Auxiliary Feedwater Flow 2 per steam generator BC.E,G

18. RCS Subcooling Margin Monitor 2 B.CEG

19. Steam Line Pressure 2 per steam generator B,C,EG

20. Refueling Water Storage Tank Level 2 BCE,G

21. DG Heat Exchanger NSWS Flow(b) 1 per DG D.G

22. Containment Spray Heat Exchanger NSWS Flow(b) 1 per train D.G (a) A channel consists of two core exit thermocouples (CETs).

(b) Not applicable If the associated outlet valve is set to Its flow balance position with power removed or If the associated outlet valve's flow balance position is fully open.

McGuire Units 1 and 2 3.3.3-4 Amendment Nos.

3.6 CONTAINMENT SYSTEMS 3.6.7 Not Used McGuire Units 1 and 2 3.6.7-1 Amendment Nos.

TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage .................................. B 3.4.14-1 B 3.4.15 RCS Leakage Detection Instrumentation ......................................... B 3.4.15-1 B 3.4.16 RCS Specific Activity .................................................. B 3.4.16-1 B 3.4.17 RCS Loops-Test Exceptions .................................................. B 3.4.17-1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1 Accumulators ............................ B 3.5.1-1 B 3.5.2 ECCS-Operating ............................ B 3.5.2-1 B 3.5.3 ECCS-Shutdown ............................ B 3.5.3-1 B 3.5.4 Refueling Water Storage Tank (RWST) ............................ B 3.5.4-1 B 3.5.5 Seal Injection Flow............................ B 3.5.5-1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1 Containment .................................................. B 3.6.1-1 B 3.6.2 Containment Air Locks .................................................. B 3.6.2-1 B 3.6.3 Containment Isolation Valves .................................................. B 3.6.3-1 B 3.6.4 Containment Pressure .................................................. B 3.6.4-1 B 3.6.5 Containment Air-Temperature .................................................. B 3.6.5-1 B 3.6.6 Containment Spray System .................................................. B 3.6.6-1 B 3.6.7 Not Used .......

B 3.6.8 Hydrogen Skimmer System (HSS) .................................................. B 3.6.8-1 B 3.6.9 Hydrogen Mitigation System (HMS) ................................................. B 3.6.9-1 B 3.6.10 Annulus Ventilation System (AVS) .................................................. B 3.6.10-1 B 3.6.11 Air Return System (ARS) .................................................. B 3.6.11-1 B 3.6.12 Ice Bed .................................................. B 3.6.12-1 B 3.6.13 Ice Condenser Doors .................................................. B 3.6.13-1 B 3.6.14 Divider Barrier Integrity .................................................. B 3.6.14-1 B 3.6.15 Containment Recirculation Drains .................................................. B 3.6.15-1 B 3.6.16 Reactor Building .................................................. B 3.6.16-1 B 3.7 PLANT SYSTEMS B 3.7.1 Main Steam Safety Valves (MSSVs) .......................... B 3.7.1-1 B 3.7.2 Main Steam Isolation Valves (MSIVs) .......................... B 3.7.2-1 B 3.7.3 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Control Valves (MFCVs), MFCV's Bypass Valves and Main Feedwater (MFW) to Auxiliary Feedwater (AFW)

Nozzle Bypass Valves (MFW/AFW NBVs) ............................... B 3.7.3-1 B 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs) ....... B 3.7.4-1 B 3.7.5 Auxiliary Feedwater (AFW) System ................................................ B 3.7.5-1 B 3.7.6 Component Cooling Water (CCW) System ...................................... B 3.7.6-1 B 3.7.7 Nuclear Service Water System (NSWS) .......................................... B 3.7.7-1 B 3.7.8 Standby Nuclear Service Water Pond (SNSWP) ............................. B 3.7.8-1 B 3.7.9 Control Room Area Ventilation System (CRAVS) ............................ B 3.7.9-1 B 3.7.10 Control Room Area Chilled Water System (CRACWS) .................... B 3.7.10-1 B 3.7.11 Auxiliary Building Filtered Ventilation Exhaust System (ABFVES) ...B 3.7.11-1 McGuire Units 1 and 2 ii Revision No. 63

PAM Instrumentation B 3.3.3 B 3.3 INSTRUMENTATION B 3.3.3 Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND The primary purpose of the PAM instrumentation is to display unit variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for Design Basis Accidents (DBAs).

The OPERABILITY of the accident monitoring instrumentation ensures that there is sufficient information available on selected unit parameters to monitor and to assess unit status and behavior following an accident.

The availability of accident monitoring instrumentation is important so that responses to corrective actions can be observed and the need for, and magnitude of, further actions can be determined.

These essential instruments are identified by unit specific documents (Ref. 1) addressing the recommendations of Regulatory Guide 1.97 (Ref. 2) as required by Supplement 1 to NUREG-0737 (Ref. 3).

The instrument channels required to be OPERABLE by this LCO include two classes of parameters identified during unit specific implementation of Regulatory Guide 1.97 as Type A and Category I variables.

Type A variables are included in this LCO because they provide the primary information required for the control room operator to take specific manually controlled actions for which no automatic control is provided, and that are required for safety systems to accomplish their safety functions for DBAs.

Category I variables are the key variables deemed risk significant because they are needed to:

Determine whether other systems important to safety are performing their intended functions;

Provide information to the operators that will enable them to determine the likelihood of a gross breach of the barriers to radioactivity release; and McGuire Units 1 and 2 B 3.3.3-1 Revision No. 63

PAM Instrumentation B 3.3.3 BASES BACKGROUND (continued)

Provide information regarding the release of radioactive materials to allow for early indication of the need to initiate action necessary to protect the public, and to estimate the magnitude of any impending threat.

These key variables are identified by the unit specific Regulatory Guide 1.97 analyses (Ref. 1). These analyses identify the unit specific Type A and Category I variables and provide justification for deviating from the NRC proposed list of Category I variables.

The specific instrument Functions listed in Table 3.3.3-1 are discussed in the LCO section.

APPLICABLE The PAM instrumentation ensures the operability of Regulatory Guide SAFETY ANALYSES 1.97 Type A and Category I variables so that the control room operating staff can:

Perform the diagnosis specified in the emergency operating procedures (these variables are restricted to preplanned actions for the primary success path of DBAs), e.g., loss of coolant accident (LOCA);

Take the specified, pre-planned, manually controlled actions, for which no automatic control is provided, and that are required for safety systems to accomplish their safety function; Determine whether systems important to safety are performing their intended functions; Determine the likelihood of a gross breach of the barriers to radioactivity release; Determine if a gross breach of a barrier has occurred; and

Initiate action necessary to protect the public and to estimate the magnitude of any impending threat.

PAM instrumentation that meets the definition of Type A in Regulatory Guide 1.97 satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4). Category I, non-Type A, instrumentation must be retained in TS because it is intended to assist operators in minimizing the consequences of accidents.

Therefore, Category I, non-Type A, variables are important for reducing public risk.

McGuire Units 1 and 2 B 3.3.3-2 Revision No. 63

PAM Instrumentation B 3.3.3 BASES LCO The PAM instrumentation LCO provides OPERABILITY requirements for Regulatory Guide 1.97 Type A monitors, which provide information required by the control room operators to perform certain manual actions specified in the unit Emergency Operating Procedures. These manual actions ensure that a system can accomplish its safety function, and are credited in the safety analyses. Additionally, this LCO addresses Regulatory Guide 1.97 instruments that have been designated Category I, non-Type A.

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

LCO 3.3.3 requires two OPERABLE channels for most Functions. Two OPERABLE channels ensure no single failure prevents operators from getting the information necessary for them to determine the safety status of the unit, and to bring the unit to and maintain it in a safe condition following an accident.

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

In some cases, the total number of channels exceeds the number of required channels, e.g., pressurizer level has a total of three channels, however only two channels are required OPERABLE. This provides additional redundancy beyond that required by this LCO, i.e., when one channel of pressurizer level is inoperable, the required number of two channels can still be met. The ACTIONS of this LCO are only entered when the required number of channels cannot be met.

Category I variables are required to meet Regulatory Guide 1.97 Category I (Ref. 2) design and qualification requirements for seismic and environmental qualification, single failure criterion, utilization of emergency standby power, immediately accessible display, continuous readout, and recording of display.

Listed below are discussions of the specified instrument Functions listed in Table 3.3.3-1.

1. Neutron Flux - (Wide Range)

Wide Range Neutron Flux indication is provided to verify reactor shutdown.

McGuire Units 1 and 2 B 3.3.3-3 Revision No. 63

PAM Instrumentation B 3.3.3 BASES LCO (continued)

Neutron flux is used for accident diagnosis, verification of subcriticality, and diagnosis of positive reactivity insertion.

Two channels of wide range neutron flux are required OPERABLE.

2, 3. Reactor Coolant System (RCS) Hot and Cold Leg Temperatures RCS Hot and Cold Leg Temperatures are Category I variables provided for verification of core cooling and long term surveillance.

RCS hot and cold leg temperatures are used to determine RCS subcooling margin. RCS subcooling margin will allow termination of safety injection (SI), if still in progress, or reinitiation of Si if it has been stopped. RCS subcooling margin is also used for unit stabilization and cooldown control.

In addition, RCS cold leg temperature is used in conjunction with RCS hot leg temperature to verify the unit conditions necessary to establish natural circulation in the RCS.

Reactor coolant hot and cold leg temperature inputs are provided by fast response resistance elements and associated transmitters in each loop.

Two channels of RCS Hot Leg Temperature and two channels of RCS Cold Leg Temperature are required OPERABLE by the LCO.

RCS Hot Leg and Cold Leg Temperature are diverse indications of RCS temperature. Core exit thermocouples also provide diverse indication of RCS temperature.

4. Reactor Coolant System Pressure (Wide Range)

RCS wide range pressure is a Category I variable provided for verification of core cooling and RCS integrity long term surveillance.

RCS pressure is used to verify delivery of SI flow to RCS from at least one train when the RCS pressure is below the pump shutoff head. RCS pressure is also used to verify closure of manually closed spray line valves and pressurizer power operated relief valves (PORVs).

McGuire Units 1 and 2 B 3.3.3-4 Revision No. 63

PAM Instrumentation B 3.3.3 BASES LCO (continued)

In addition to these verifications, RCS pressure is used for determining RCS subcooling margin. RCS pressure can also be used:

to determine whether to terminate actuated SI or to reinitiate stopped SI;

to Determine when to reset SI and shut off low head SI;

to manually restart low head SI; as reactor coolant pump (RCP) trip criteria; and to make a determination on the nature of the accident in progress and where to go next in the procedure.

RCS pressure is also related to three decisions about depressurization. They are:

to determine whether to proceed with primary system depressurization; to verify termination of depressurization; and to determine whether to close accumulator isolation valves during a controlled cooldown/depressurization.

A final use of RCS pressure is to determine whether to operate the pressurizer heaters.

RCS pressure is a Type A variable because the operator uses this indication to monitor the cooldown of the RCS following a steam generator tube rupture (SGTR) or small break LOCA. Operator actions to maintain a controlled cooldown, such as adjusting steam generator (SG) pressure or level, would use this indication.

Furthermore, RCS pressure is one factor that may be used in decisions to terminate RCP operation.

Two channels of wide range RCS pressure are required OPERABLE.

McGuire Units 1 and 2 B 3.3.3-5 Revision No. 63

PAM Instrumentation B 3.3.3 BASES LCO (continued) 5, 6. Reactor Vessel Water Level Reactor Vessel Water Level is provided for verification and long term surveillance of core cooling. It is also used for accident diagnosis and to determine reactor coolant inventory adequacy.

The Reactor Vessel Water Level Monitoring System provides a direct measurement of the collapsed liquid level above the fuel alignment plate. The collapsed level represents the amount of liquid mass that is in the reactor vessel above the core.

Measurement of the collapsed water level is selected because it is a direct indication of the water inventory.

Two channels of Reactor Vessel Water Level are provided in both the core region (lower range) and the head region (wide range) with indication in the unit control room. Each channel uses differential pressure transmitters and a microprocessor to calculate true vessel level or relative void content of the primary coolant.

7. Containment Sump Water Level (Wide Range)

Containment Sump Water Level is provided for verification and long term surveillance of RCS integrity.

Containment Sump Water Level is used to determine:

containment sump level accident diagnosis;

when to begin the recirculation procedure; and

whether to terminate Si, if still in progress.

Two channels of wide range level are required OPERABLE.

8. Containment Pressure (Wide Range)

Containment Pressure (Wide Range) is provided for verification of RCS and containment OPERABILITY.

Containment pressure is used to verify closure of main steam isolation valves (MSIVs), and containment spray Phase B isolation when Containment Pressure - High High is reached.

McGuire Units 1 and 2 B 3.3.3-6 Revision No. 63

PAM Instrumentation B 3.3.3 BASES LCO (continued)

Two channels of wide range containment pressure are required OPERABLE.

9. Containment Atmosphere Radiation (High Range)

Containment Atmosphere 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 a high energy line break (HELB) has occurred, and whether the event is inside or outside of containment.

Two channels of high range containment atmosphere radiation are provided. One channel is required OPERABLE. Diversity is provided by portable instrumentation or by sampling and analysis.

10. Not Used

11. 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.

Three channels of pressurizer level are provided. Two channels are required OPERABLE.

12. Steam Generator Water Level (Narrow Range)

SG Water Level is provided to monitor operation of decay heat removal via the SGs. The Category I indication of SG level is the narrow range level instrumentation.

McGuire Units 1 and 2 B 3.3.3-7 Revision No. 63

PAM Instrumentation B 3.3.3 BASES LCO (continued)

SG Water Level (Narrow Range) is used to:

identify the faulted 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 an SGTR); and

verify unit conditions for termination of SI during secondary unit HELBs outside containment.

Four channels per SG of narrow range water level are provided.

Only two channels are required OPERABLE by the LCO.

13, 14, 15, 16. Core Exit Temperature Core Exit Temperature is provided for verification and long term surveillance of core cooling.

Adequate core cooling is ensured with two valid Core Exit Temperature channels per quadrant with two CETs per required channel. Core inlet temperature data is used with core exit temperature to give radial distribution of coolant enthalpy rise across the core. Core Exit Temperature is used to determine whether to terminate SI, if still in progress, or to reinitiate SI if it has been stopped. Core Exit Temperature is also used for unit stabilization and cooldown control.

Two OPERABLE channels of Core Exit Temperature are required in each quadrant to provide indication of radial distribution of the coolant temperature rise across representative regions of the core.

Two sets of two thermocouples (1 set from each redundant power train) ensure a single failure will not disable the ability to determine the radial temperature gradient.

17. Auxiliary Feedwater Flow AFW Flow is provided to monitor operation of decay heat removal via the SGs.

McGuire Units 1 and 2 B 3.3.3-8 Revision No. 63

PAM Instrumentation B 3.3.3 BASES LCO (continued)

The AFW Flow to each SG is determined by flow indicators, pump operational status indicators, and NSWS and condensate supply valve indicators in the control room. The AFW flow indicators are category 2, type D variables which are used to demonstrate the category 1 variable of AFW assured source.

AFW flow is used three ways:

to verify delivery of AFW flow to the SGs; to determine whether to terminate SI if still in progress, in conjunction with SG water level (narrow range); and to regulate AFW flow so that the SG tubes remain covered.

18. RCS Subcooling Margin Monitor RCS subcooling is provided to allow unit stabilization and cooldown control. RCS subcooling will allow termination of SI, if still in progress, or reinitiation of SI if it has been stopped.

The margin to saturation is calculated from RCS pressure and temperature measurements. The average of the five highest core exit thermocouples are used to represent core conditions and the wide range hot leg RTDs are used to measure loop hot leg temperatures. The plant computer performs the calculations and comparisons to saturation curves. A graphic display over the required range gives the operator a representation of primary system conditions compared to various curves of importance (saturation, NDT, etc.).

A backup program exists to ensure the capability to accurately monitor RCS subcooling. The program includes training and a procedure to manually calculate subcooling margin, using control room-pressure and temperature instruments.

19. Steam Line Pressure Steam Line Pressure is provided to monitor operation of decay heat removal via the SGs. Steam line pressure is also used to determine if a high energy secondary line rupture occurred and which SG is faulted.

McGuire Units 1 and 2 B 3.3.3-9 Revision No. 63

PAM Instrumentation B 3.3.3 BASES LCO (continued)

Two channels of Steam Line Pressure are required OPERABLE.

20. Refueling Water Storage Tank Level RWST level monitoring is provided to ensure an adequate supply of water to the safety injection and spray pumps during the switchover to cold leg recirculation.

Three channels of RWST level are provided. Two channels are required OPERABLE by the LCO.

21. OG Heat Exchanger NSWS Flow Flow indicators are provided in each of the NSWS trains to indicate cooling water flow through the respective train DG. These indicators are provided for operators to manually control flow to the DG heat exchanger. One flow indicator is required OPERABLE on each train.

22. Containment Spray Heat Exchanger NSWS Flow Flow indicators are provided in each of the NSWS trains to indicate cooling water flow through the respective train containment spray heat exchangers. These indicators are provided for operators to manually control flow to the heat exchanger. One flow indicator is required OPERABLE on each train.

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2, and 3.

These variables are related to the diagnosis and pre-planned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1, 2, and 3. In MODES 4, 5, and 6, unit conditions are such that the likelihood of an event that would require PAM instrumentation is low; therefore, the PAM instrumentation is not required to be OPERABLE in these MODES.

ACTIONS A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.3-1. When the Required Channels in Table 3.3.3-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.

The Completion Time(s) of the inoperable channel(s) of a Function will be McGuire Units 1 and 2 B 3.3.3-1 0 Revision No. 63

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued) tracked separately for each Function starting from the time the Condition was entered for that Function.

A.1 Condition A applies to all PAM instrument Functions. Condition A addresses the situation when one or more required channels for one or more Functions are inoperable. The Required Action is to refer to Table 3.3.3-1 and take the appropriate Required Actions for the PAM instrumentation affected. The Completion Times are those from the referenced Conditions and Required Actions.

B.1 Condition B applies when one or more Functions have one required channel that is inoperable. Required Action B.1 requires restoring the inoperable channel to OPERABLE status within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE channel, the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval. Condition B is not applicable to functions with a single required channel.

C.1 Condition C applies when the Required Action and associated Completion Time for Condition B are not met. This Required Action specifies initiation of actions in Specification 5.6.7, which requires a written report to be submitted to the NRC immediately. This report discusses the results of the root cause evaluation of the inoperability and identifies proposed restorative actions. This action is appropriate in lieu of a shutdown requirement since alternative actions are identified before loss of functional capability, and given the likelihood of unit conditions that would require information provided by this instrumentation.

McGuire Units 1 and 2 B 3.3.3-1 1 Revision No. 63

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)

D.1 Condition D applies when a single require channel is inoperable.

Required Action D.1 requires restoring the required channel 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 the required channel inoperable is not acceptable. Therefore, requiring restoration of the required channel to OPERABLE status limits the risk that the PAM function will be in a degraded condition should an event occur.

E.1 Condition E applies when one or more Functions have two inoperable required channels (i.e., two channels inoperable in the same Function).

Required Action E.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.

Condition E does not apply to hydrogen monitor channels and functions with single channels.

F.1 Not Used G.1 and G.2 If the Required Action and associated Completion Time of Conditions D or E are 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 conditions in an orderly manner and without challenging unit systems.

McGuire Units 1 and 2 B 3.3.3-12 Revision No. 63

PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)

HA Alternate means of monitoring Containment Area Radiation have been developed and tested. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. If these alternate means are used, the Required Action is not to shut down the unit but rather to follow the directions of Specification 5.6.7, in the Administrative Controls section of the TS. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels.

SURVEILLANCE A Note has been added to the SR Table to clarify that REQUIREMENTS SR 3.3.3.1 and SR 3.3.3.3 apply to each PAM instrumentation Function in Table 3.3.3-1.

Performing the Neutron Flux Instrumentation and Containment Atmosphere Radiation (High-Range) surveillances meets the License Renewal Commitments for License Renewal Program for High-Range Radiation and Neutron Flux Instrumentation Circuits per UFSAR Chapter 18, Table 18-1 and License Renewal Commitments Specification MCS-1274.00-00-0016, Section 4.44.

SR 3.3.3.1 Performance of the CHANNEL CHECK once every 31 days ensures that a gross instrumentation failure has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar unit instruments located throughout the unit.

McGuire Units 1 and 2 B 3.3.3-13 Revision No. 63

PAM Instrumentation B 3.3.3 BASES SURVEILLANCE REQUIREMENTS (continued)

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. The calibration method for neutron detectors is specified in the Bases of LCO 3.3.1, "Reactor Trip System (RTS)

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

REFERENCES 1. UFSAR Section 1.8.

2. Regulatory Guide 1.97, Rev. 2.

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

4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

McGuire Units 1 and 2 B 3.3.3-14 Revision No. 63

B 3.6.7 l B 3.6 CONTAINMENT SYSTEMS B 3.6.7 Not Used I McGuire Units 1 and 2 B 3.6.7-1 Revision No. 63

HSS B 3.6.8 B 3.6 CONTAINMENT SYSTEMS B 3.6.8 Hydrogen Skimmer System (HSS)

BASES BACKGROUND The HSS reduces the potential for breach of containment due to a hydrogen oxygen reaction by providing a uniformly mixed post accident containment atmosphere, thereby minimizing the potential for local hydrogen burns due to a pocket of hydrogen above the flammable concentration. Maintaining a uniformly mixed containment atmosphere also ensures that the hydrogen monitors will give an accurate measure of the bulk hydrogen concentration and give the operator the capability of preventing the occurrence of a bulk hydrogen bum inside containment per 10 CFR 50.44, "Standards for Combustible Gas Control Systems in Light-Water-Cooled Reactors" (Ref. 1), and 10 CFR 50, GDC 41, "Containment Atmosphere Cleanup" (Ref. 2).

The post accident HSS is an Engineered Safety Feature (ESF) and is designed to withstand a loss of coolant accident (LOCA) without loss of function. The System has two independent trains, each consisting of two fans with their own motors and controls. Each train is sized for 3000 cfm.

There is a normally closed, motor-operated valve on the hydrogen skimmer suction line to reduce ice condenser bypass during initial blowdown. The two trains are initiated automatically on a containment pressure high-high signal. The automatic action is to open the motor operated valve on the hydrogen skimmer suction line after a 9+/-h 1 minute delay. Once the valve has fully opened, the hydrogen skimmer fan will start. Each train is powered from a separate emergency power supply.

Since each train fan can provide 100% of the mixing requirements, the System will provide its design function with a limiting single active failure.

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

McGuire Units 1 and 2 B 3.6.8-1 Revision No. 63

HSS B 3.6.8 BASES APPLICABLE. - The HSS provides the capability for reducing the local hydrogen SAFETY ANALYSES concentration to approximately the bulk average concentration. The limiting DBA relative to hydrogen concentration is a LOCA.

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

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

b. Radiolytic decomposition of water in the Reactor Coolant System (RCS) and the containment sump;

c. Hydrogen in the RCS at the time of the LOCA (i.e., hydrogen dissolved in the reactor coolant and hydrogen gas in the pressurizer vapor space); or

d. Corrosion of metals exposed to containment spray and Emergency Core Cooling System solutions.

To evaluate the potential for hydrogen accumulation in containment following a LOCA, the hydrogen generation as a function of time following the initiation of the accident is calculated. Conservative assumptions recommended by Reference 3 are used to maximize the amount of hydrogen calculated.

The HSS satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4).

LCO Two HSS trains must be OPERABLE, with power to each from an independent, safety related power supply. Each train consists of one fan with its own motor and controls and is automatically initiated by a containment pressure high-high signal.

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

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

In MODE 3 or 4, both the hydrogen production rate and the total hydrogen produced after a LOCA would be less than that calculated for McGuire Units I and 2 B 3.6.8-2 Revision No. 63

HSS B 3.6.8 BASES APPLICABILITY (continued) the DBA LOCA. Also, because of the limited time in these MODES, the probability of an accident requiring the HSS is low. Therefore, the HSS is not required in MODE 3 or 4.

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

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

B.1 If an inoperable HSS train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

McGuire Units I and 2 B 3.6.8-3 Revision No. 63

HSS B 3.6.8 BASES SURVEILLANCE SR 3.6.8.1 REQUIREMENTS Operating each HSS train for Ž 15 minutes ensures that each train is OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, fan and/or motor failure, or excessive vibration can be detected for corrective action. The 92 day Frequency is consistent with Inservice Testing Program Surveillance Frequencies, operating experience, the known reliability of the fan motors and controls, and the two train redundancy available.

SR 3.6.8.2 Verifying HSS fan motor current at rated speed with the motor operated suction valves closed is indicative of overall fan motor performance and system flow. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of 92 days was based on operating experience which has shown this Frequency to be acceptable.

SR 3.6.8.3 This SR verifies the operation of the motor operated suction valves and HSS fans in response to a start permissive from the Containment Pressure Control System (CPCS). The CPCS is described in the Bases for LCO 3.3.2, "ESFAS." The Frequency of 92 days was based on operating experience which has shown this Frequency to be acceptable.

SR 3.6.8.4 This SR ensures that each HSS train responds properly to a containment pressure high-high actuation signal. The Surveillance verifies that each fan starts after a delay of 2 8 minutes and < 10 minutes. The Frequency of 92 days conforms with the testing requirements for similar ESF equipment and considers the known reliability of fan motors and controls and the two train redundancy available. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

McGuire Units 1 and 2 B 3.6.8-4 Revision No. 63

HSS B 3.6.8 BASES REFERENCES 1. 10 CFR 50.44.

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

3. Regulatory Guide 1.7, Revision 0.

4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

McGuire Units 1 and 2 B 3.6.8-5 Revision No. 63

HMS B 3.6.9 B 3.6 CONTAINMENT SYSTEMS B 3.6.9 Hydrogen Mitigation System (HMS)

BASES BACKGROUND The HMS reduces the potential for breach of primary containment due to a hydrogen oxygen reaction in post accident environments. The HMS is required by 10 CFR 50.44, "Standards for Combustible Gas Control Systems in Light-Water-Cooled Reactors" (Ref. 1), and Appendix A, GDC 41, "Containment Atmosphere Cleanup" (Ref. 2), to reduce the hydrogen concentration in the primary containment following a degraded core accident. The HMS must be capable of handling an amount of hydrogen equivalent to that generated from a metal water reaction involving 75% of the fuel cladding surrounding the active fuel region (excluding the plenum volume).

10 CFR 50.44 (Ref. 1) requires units with ice condenser containments to install suitable hydrogen control systems that would accommodate an amount of hydrogen equivalent to that generated from the reaction of 75% of the fuel cladding with water. The HMS provides this required capability. This requirement was placed on ice condenser units because of their small containment volume and low design pressure (compared with pressurized water reactor dry containments). Calculations indicate that if hydrogen equivalent to that generated from the reaction of 75% of the fuel cladding with water were to collect in the primary containment, the resulting hydrogen concentration would be far above the lower flammability limit such that, if ignited from a random ignition source, the resulting hydrogen burn would seriously challenge the containment and safety systems in the containment.

The HMS is based on the concept of controlled ignition using thermal ignitors, designed to be capable of functioning in a post accident environment, seismically supported, and capable of actuation from the control room. A total of 70 ignitors are distributed throughout the various regions of containment in which hydrogen could be released or to which it could flow in significant quantities. The ignitors are arranged in two independent trains such that each containment region has at least two ignitors, one from each train, controlled and powered redundantly so that ignition would occur in each region even if one train failed to energize.

When the HMS is initiated, the ignitor elements are energized and heat up to a surface temperature 2 17000 F. At this temperature, they ignite the hydrogen gas that is present in the airspace in the vicinity of the ignitor.

The HMS depends on the dispersed location of the ignitors so Reviaion No. 63 McGuire Units and 2 Units I1 and 2 B 3.6.9-1 B 3.6.9-1 ReViaion No. 63

HMS B 3.6.9 BASES BACKGROUNp (continued) that local pockets of hydrogen at increased concentrations would burn before reaching a hydrogen concentration significantly higher than the lower flammability limit. Hydrogen ignition in the vicinity of the ignitors is assumed to occur when the local hydrogen concentration reaches 8.5 volume percent (v/o) and results in 100% of the hydrogen present being consumed.

APPLICABLE The HMS causes hydrogen in containment to bum in a controlled manner SAFETY ANALYSES as it accumulates following a degraded core accident (Ref. 3). Burning occurs at the lower flammability concentration, where the resulting.

temperatures and pressures are relatively benign. Without the system, hydrogen could build up to higher concentrations that could result in a violent reaction if ignited by a random ignition source after such a buildup.

The hydrogen ignitors are not included for mitigation of a Design Basis Accident (DBA) because an amount of hydrogen equivalent to that generated from the reaction of 75% of the fuel cladding with water is far in excess of the hydrogen calculated for the limiting DBA loss of coolant accident (LOCA). The hydrogen ignitors have been shown by probabilistic risk analysis to be a significant contributor to limiting the severity of accident sequences that are commonly found to dominate risk for units with ice condenser containments. As such, the hydrogen ignitors satisfy Criterion 4 of 10 CFR 50.36 (Ref. 4).

LCO Two HMS trains must be OPERABLE with power from two independent, safety related power supplies.

For this unit, an OPERABLE HMS train consists of 34 of 35 ignitors energized on the train.

Operation with at least one HMS train ensures that the hydrogen in containment can be burned in a controlled manner. Unavailability of both HMS trains could lead to hydrogen buildup to higher concentrations, which could result in a violent reaction if ignited. The reaction could take place fast enough to lead to high temperatures and overpressurization of containment and, as a result, breach containment or cause containment leakage rates above those assumed in the safety analyses. Damage to safety related equipment located in containment could also occur.

Reviaion No. 63 McGuire Units I and Units 1 2 and 2 B 3.6.9-2 B 3.6.9-2 Reviaion No. 63

HMS B 3.6.9 BASES APPLICABILITY Requiring OPERABILITY in MODES 1 and 2 for the HMS ensures its immediate availability after safety injection and scram actuated on a LOCA initiation. In the post accident environment, the two HMS subsystems are required to control the hydrogen concentration within containment to near its flammability limit of 4.0 v/o assuming a worst case single failure. This prevents overpressurization of containment and damage to safety related equipment and instruments located within containment.

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

Therefore, the HMS is not required in MODES 3 and 4.

In MODES 5 and 6, the probability and consequences of a LOCA are reduced due to the pressure and temperature limitations of these MODES. Therefore, the HMS is not required to be OPERABLE in MODES 5 and 6.

ACTIONS A.1 and A.2 With one HMS train inoperable, the inoperable train must be restored to OPERABLE status within 7 days or the OPERABLE train must be verified OPERABLE frequently by performance of SR 3.6.9.1. The 7 day Completion Time is based on the low probability of the occurrence of a degraded core event that would generate hydrogen in amounts equivalent to a metal water reaction of 75% of the core cladding, the length of time after the event that operator action would be required to prevent hydrogen accumulation from exceeding this limit, and the low probability of failure of the OPERABLE HMS train. Alternative Required Action A.2, by frequent surveillances, provides assurance that the OPERABLE train continues to be OPERABLE.

B.1 Condition B is one containment region with no OPERABLE hydrogen ignitor. Thus, while in Condition B, or in Conditions A and B simultaneously, there would always be ignition capability in the adjacent containment regions that would provide redundant capability by flame propagation to the region with no OPERABLE ignitors.

Required Action B.1 calls for the restoration of one hydrogen ignitor in each region to OPERABLE status within 7 days. The 7 day Completion Time is based on the same reasons given under Required Action A1.

Reviaion No. 63 McGuire Units McGuire and 2 Units I1 and 2 B 3.6.9-3 B 3.6.9-3 Reviaion No. 63

HMS B 3.6.9 BASES ACTIONS (continued)

C.1 The unit must be placed in a MODE in which the LCO does not apply if the HMS subsystem(s) cannot be restored to OPERABLE status within the associated Completion Time. This is done by placing the unit in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . The allowed Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.9.1 REQUIREMENTS This SR confirms that Ž 34 of 35 hydrogen ignitors can be successfully energized in each train. The ignitors are simple resistance elements.

Therefore, energizing provides assurance of OPERABILITY. The allowance of one inoperable hydrogen ignitor is acceptable because, although one inoperable hydrogen ignitor in a region would compromise redundancy in that region, the containment regions are interconnected so that ignition in one region would cause burning to progress to the others (i.e., there is overlap in each hydrogen ignitor's effectiveness between regions). The Frequency of 92 days has been shown to be acceptable through operating experience.

SR 3.6.9.2 This SR confirms that the two inoperable hydrogen ignitors allowed by SR 3.6.9.1 (i.e., one in each train) are not in the same containment region. The Frequency of 92 days is acceptable based on the Frequency of SR 3.6.9.1, which provides the information for performing this SR.

SR 3.6.9.3 A more detailed functional test is performed every 18 months to verify system OPERABILITY. Each glow plug is visually examined to ensure that it is clean and that the electrical circuitry is energized. All ignitors (glow plugs), including normally inaccessible ignitors, are visually checked for a glow to verify that they are energized. Additionally, the surface temperature of each glow plug is measured to be > 1700°F to demonstrate that a temperature sufficient for ignition is achieved. The 18 month Frequency is based on the need to perform this Surveillance Reviaion No. 63 McGuire Units McGuire and 22 Units I1 and B 3.6.9-4 B 3.6.9-4 Reviaion No. 63

HMS B 3.6.9 BASES SURVEILLANCE REQUIREMENTS (continued) under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. 10 CFR 50.44.

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

3. UFSAR, Section 6.2.

4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

Revialon No. 63 McGuire Units and 2 Units II and 2 B 3.6.9-5 B 3.6.9-5 Revialon No. 63

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