ML042790461
| ML042790461 | |
| Person / Time | |
|---|---|
| Site: | Oconee, Mcguire, McGuire  |
| Issue date: | 09/20/2004 |
| From: | Mccollum W Duke Energy Corp |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| Download: ML042790461 (39) | |
Text
_ Duke WILLIAM RMCCOLLUM, JR.
riwtwere VP, Nuclear Support Duke Energy Corporation A Duke Energy Company Duke Power EC07H / 526 South Church Street Charlotte, NC 28202-1802 Mailing Address:
P. 0. Box 1006 - EC07H Charlotte, NC 28201-1006 704 382 8983 704 382 6056 fax wrmccoll@duke-energy. corn September 20, 2004 U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 ATTENTION: Document Control Desk
Subject:
Duke Energy Corporation Oconee Nuclear Station, Units 1, 2, and 3 Docket Nos. 50-269, 270, and 50-287 McGuire Nuclear Station, Units 1 and 2 Docket Nos. 50-369 and 50-370 License Amendment Request to Eliminate the Technical Specifications Requirements for the Hydrogen Monitors and Hydrogen Recombiners Oconee Technical Specification 3.3.8 and McGuire Technical Specifications 3.3.3 and 3.6.7, Using the Consolidated Line Item Improvement Process In accordance with the provisions of 10 CFR 50.90, Duke Energy Corporation (Duke) is submitting a license amendment request (LAR) for the Facility Operating Licenses and Technical Specifications (TS) for Oconee Nuclear Station, Units 1, 2, and 3 and McGuire Nuclear Station, Units 1 and
- 2. The proposed amendment would eliminate the Oconee TS 3.3.8 requirements and the McGuire TS 3.3.3 requirements for the Hydrogen Monitors, and the McGuire TS 3.6.7 requirements for the Hydrogen Recombiners. Conforming changes are also being made to the associated Bases affected by this LAR and these Bases changes are included in this submittal package. This change is consistent with an NRC approved Industry/Technical Specification Task Force (TSTF) Standard Technical Specifications Change Traveler, TSTF-447, Revision 1, Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors.
www.dukepower.com , ) j
U. S. Nuclear Regulatory Commission September 20, 2004 Page 2 provides a description of the proposed change, the requested confirmation of applicability, and plant-specific verifications and commitments. Attachments 2a and 2b provide the existing TS and Bases pages marked-up to show the proposed changes for Oconee and McGuire, respectively. Attachments 3a and 3b providing revised, clean TS and Bases pages for Oconee and McGuire, respectively, will be provided to the NRC at the time of issuance of the approved amendments.
Implementation of this proposed change to the Oconee and McGuire Facility Operating Licenses and TS will require revision to the Oconee and McGuire Updated Final Safety Analysis Reports (UFSAR). Necessary UFSAR changes will be submitted in accordance with 10 CFR 50.71(e).
Duke requests approval of this Consolidated Line Item Improvement Process (CLIIP) item by March 1, 2005, with each station's implementation to take place 60 days after completion of the Spring 2005 refueling outages. For Oconee this outage is lEOC22 on Unit 1, and for McGuire, this outage is 2EOC16 on Unit 2. Regulatory commitments applicable to this LAR are described in Attachment 1, Section 6.1.
In accordance with Duke administrative procedures and the Quality Assurance Program Topical Report, the plant-specific changes contained in this proposed amendment have been reviewed and approved by the respective Oconee or McGuire Plant Operations Review Committee. This LAR has also been reviewed and approved by the Duke Nuclear Safety Review Board. Pursuant to 10 CFR 50.91, a copy of this amendment request is being sent to the designated officials of the State of North Carolina and the State of South Carolina.
U. S. Nuclear Regulatory Commission September 20, 2004 Page 3 Inquiries on this request should be directed to J. S.
Warren at (704) 875-5171.
Very truly yours, W. R. McCollum, Attachments:
- 1. Description and Assessment 2a. Proposed Technical Specifications and Bases Changes (Mark-up) for Oconee 2b. Proposed Technical Specifications and Bases Changes (Mark-up) for McGuire 3a. Revised (Clean) Technical Specifications and Bases Pages for Oconee - FUTURE 3b. Revised (Clean) Technical Specifications and Bases Pages for McGuire - FUTURE
U. S. Nuclear Regulatory Commission September 20, 2004 Page 4 xc (with 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 Project Manager (Oconee)
U. S. Nuclear Regulatory commission Mail Stop 0-8 H12 Washington, DC 20555-0001 J. J. Shea (Addressee Only)
NRC Project Manager (McGuire)
U. S. Nuclear Regulatory commission Mail Stop 0-8 H12 Washington, DC 20555-0001 M. C. Shannon Senior Resident Inspector U. S. Nuclear Regulatory Commission Oconee Nuclear Site J. B. Brady Senior Resident Inspector U. S. Nuclear Regulatory Commission McGuire Nuclear Site Beverly 0. Hall, Section Chief Radiation Protection Section 1645 Mail Service Center Raleigh, NC 27699-1645 H. J. Porter, Director Division of Radioactive Waste Management South Carolina Bureau of Land and Waste Management 2600 Bull Street Columbia, SC 29201
U. S. Nuclear Regulatory Commission September 20, 2004 Page 5 W. R. McCollum, Jr., being duly sworn, affirms that he is the person who subscribed his name to the foregoing statement, and that all matters and facts set forth herein are true and correct to the best of his knowledge.
W. R. McCollum, Jr., V resident, Nuclear Support Subscribed and sworn to me: Z4 ,-Io
+& otary Public My commission expires: -7X4X4- e'? "-O-O 2
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U. S. Nuclear Regulatory Commission September 20, 2004 Page 6 bxc (with attachments):
L. A. Keller B. G. Davenport K. L. Crane J. E. Smith ELL Oconee Master File - ON03DM McGuire Master File - MGO1DM
ATTACHMENT 1 DESCRIPTION AND ASSESSMENT
1.0 INTRODUCTION
The proposed license amendment eliminates the Oconee Nuclear Station Technical Specifications (TS) 3.3.8 requirements for the Hydrogen Monitors and the McGuire Nuclear Station TS 3.3.3 requirements for the Hydrogen Monitors and the TS 3.6.7 requirements for the Hydrogen Recombiners.
The changes are consistent with an NRC approved Industry/Technical Specifications Task Force (TSTF)
Standard Technical Specifications Change Traveler, TSTF-447, Revision 1, 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:
For Oconee:
Revised - TS 3.3.8, Condition C (for consistency with the deletion of Function 10)
Deleted - TS 3.3.8, Condition D (Two required channels for Function 10 inoperable)
Revised - TS 3.3.8, Condition G (for consistency with the deletion of Condition\D)
Revised - SR 3.3.8.2, Channel Calibration (for consistency with the deletion of Function 10)
Revised - SR 3.3.8.3, Channel Calibration (for consistency with the deletion of Function 10) 1
ATTACHMENT 1 Deleted - In Table 3.3.8-1, Item 10, Containment Hydrogen Concentration (Hydrogen Monitors)
For McGuire:
Deleted - TS 3.3.3, Condition F (Two hydrogen monitor channels inoperable)
Revised - TS 3.3.3, Condition G (for consistency with the deletion of Condition F)
Deleted - SR 3.3.3.2 (Channel Calibration for Hydrogen Monitors)
Deleted - In Table 3.3.3-1, Item 10 (Hydrogen Monitors)
Deleted - TS 3.6.7 (Hydrogen Recombiners)
Other changes included in this amendment are limited to formatting changes that resulted directly from the deletion of the above requirements related to the hydrogen monitors and the hydrogen recombiners.
As described in the NRC-approved Revision 1 of TSTF-447, the changes to the TS requirements result in changes to various TS Bases sections. Proposed changes to the TS Bases are also addressed in Attachments 2a and 2b and the forthcoming Attachments 3a and 3b.
3.0 BACKGROUND
The background for this amendment is adequately addressed by the NRC Notice of Availability published on September 25, 2003 (68 FR 55416), TSTF-447, Revision 1, the documentation associated with the 10 CFR 50.44 rule making, and other related documents.
4.0 REGULATORY REQUIREMENTS AND GUIDANCE The applicable regulatory requirements and guidance associated with this amendment are adequately addressed by the NRC Notice of Availability published on September 25, 2003 (68 FR 55416), TSTF-447, Revision 1, the documentation 2
ATTACHMENT 1 7.0 NO SIGNIFICANT HAZARDS CONSIDERATION Duke has reviewed the proposed no significant hazards consideration determination published on September 25, 2003 (68 FR 55416), as part of the CLIIP. Duke has concluded that the determination is applicable to Oconee and McGuire and is hereby incorporated by reference to satisfy the requirement of 10 CFR 50.91(a).
8.0 ENVIRONMENTAL EVALUATION Duke has reviewed the environmental evaluation included in the model SE published on September 25, 2003 (68 FR 55416),
as part of the CLIIP. Duke has concluded the staff's findings presented in that evaluation are applicable to Oconee and McGuire and the evaluation is hereby incorporated by reference for this amendment.
9.0 PRECEDENT This amendment is being made in accordance with the CLIIP.
Duke is not proposing variations or deviations from the TS changes described in TSTF-447, Revision 1, or the staff's model SE published on September 25, 2003 (68 FR 55416) other than the TS are not being renumbered ("Not used" is being inserted into the deleted portions). Note that Oconee does not have TS for hydrogen recombiners, thus the portion of the CLIIP that addresses deletion of the TS for hydrogen recombiners does not apply to Oconee.
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 Consolidated Line Item Improvement Process, published September 25, 2003 (68 FR 55416).
4
ATTACHMENT 2a Oconee Nuclear Station Units 1, 2, and 3 Proposed Technical Specifications and Bases Changes (Mark-up)
PAM Instrumentation 3.3.8 C. ----------- NOTE----------- C.1 Restore one channel to 7 days Not applicable to OPERABLE status. I Functionsf14, 18, 19, 20 anid 22.
One or more Functions with two required channels inoperable.
D.
E. ----------- NOTE----------- I E.1 Restore required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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. E 0
PAM Instrumentation 3.3.8 ACTIONS (continued)
CONDiTION REQUIRED ACTION COMPLETION TIME F. -----------NOTE----------- F.1 Deciare ihe 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 Completions referenced in Time of Condition CTable 3.3.8-1 for the or E not met. channel.
H. As required by H.1 Be in MODE 3. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Required Action G.1 and referenced in AND Table 3.3.8-1.
H.2 Be in MODE 4. 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> 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.g . Q3,
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 7Wand 22.
Perform CHANNEL CALIBRATION. 12 months SR 3.3.8.3 ------------------------- NOTES------------------------ I
- 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 Nosw
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 I
- 3. RCS Hot Leg Level 2 H
- 4. RCS Pressure (Wide Range) 2
- 5. Reactor Vessel Head Level 2 H
- 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(a)(b)c)
- 9. Containment Area Radiation (High Range) 2 10.
- 11. Pressurizer Level H
- 12. Steam Generator Water Level 2 H
- 13. Steam Generator Pressure 2 per SG 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 1 per train NA
- 20. Reactor Building Spray Flow 1 per train NA
- 22. Low Pressure Service Water Flow to LPI Coolers 1 pertrain NA (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) 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.sI, 7
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. Contain nt Hvdrocen Cncentration /1lco7 sseg(
Cont ment Hydroge oncentration instrume ation is a Type Psregory 1 varel intru A, ded to detect hiAh, yCrogen 1 cue ntration con that represent a potial for contaimnet wtrh. lThis varile talso important inconifying the a racy mingating io act' s. The Containmen . Thdrogen Concessr ion instrumentation consists of two channels (MT 80 and 8 with readout on twoindicators and on recorded.nhe f B hnnel indicated rioe is 0 to 10% hydraen concentration
- 11. Pressurizer Level Pressu(zer Level instrumentation is a Type A, Category 1 variable used in combination with other system parameters to determine whether to terminate safety injection (SI), if still in progress, or to reinitiate Svif 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 (11I% to 84%
level as a percentage of volume).
OCONEE UNITS 1, 2, & 3 B 3.3.8-7 BASES REVISION DATED
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(O 14,18, 19, 20, and 22.
D.1 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 <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 3.3.8-1 5 BASES REVISION DATED ~I7
PAM Instrumentation B 3.3.8 BASES ACTIONS F.1 (continued) and the requirements of LCO 3.5.2, LCO 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, Mor 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 BASES REVISION DATEDH3 l
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 7giand 22. SR 3.3.8 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,N 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 BASES REVISION DATED k 3
ATTACH24ENT 2b McGuire Nuclear Station Units 1 and 2 Proposed Technical Specifications and Bases Changes (Mark-up)
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 Isoiation Valves ................................................. 3.6.3-1 3.6.4 Containment Pressure ................................................. 3.6.4-1 3.6.5 Containment Air Temperature ................................................. 3.6.5-1 366Containment Spr -ystm........................................................... 3.6.6-1 3.6.7 N+ (ISJA dr en Yeco binr r 3.6.8 -/Hydrogen Skimmner 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.1i/1I
- TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)
B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage i . ......................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 ro n Reombeersf .
B 3.6.8 Hydrogen Skimmer Sytem (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 MAain 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.
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. T o hydr gen m nitor F.1 Res re on hydrog n a~nbnl inoperpig mgio chnnel to 9e~~ OP~ERB statv G. Required Action and G.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition Dx E AND
(; not met.
la G.2 Be in MODE 4. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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. 6R
PAM Instrumentation 3.3.3 SURVEILLANCE REQUIREMENTS
-- - --------- --------- - ----------------- - ---- ----- - ]'ML j r- - ------- - --------------- - ------------ -------------- - ----
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-----I-This SR inly applicable Hydrogen Mo ors. c)0t
\-4 1 ------- CIAO ------ V eromCHAN LCLIBRATION.
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.rlp/-169)
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.E.G
- 2. Reactor Coolant System (RCS) Hot Leg Temperature 2 8.C,EG
- 3. RCS Cold Leg Temperature 2 B,C.EG
- 4. FCS Pressure (Wide Range) 2 BCE.G
- 5. Reactor Vessel Water Level (Dynamic Head Range) 2 B.C,EG
- 6. Reactor Vessel Water Level (Lower Range) 2 B.C.E.G
- 7. Containment Sump Water Level (Wide Range) 2 B,C.E.G
- 8. Containment Pressure (Wide Range) 2 B,C.E.G
- 9. Containment Atmosphere Radiation (High Range) I DH
- 10. rs/ / 2/
2rogeMonit B.C G
- 11. Pressurizer Level-~ I~Vec 2 B.C.E.G
- 12. Steam Generator Water Level (Narrow Range) 2 per steam generator BCEG
- 13. Core Exit Temperature - Quadrant 1 2 (a) BC.E.G
- 14. Core Exit Temperature - Quadrant 2 2 (a) B,C.E.G
- 15. Core Exit Temperature - Quadrant 3 2 (a) B,C,E,G
- 16. Core Exit Temperature - Quadrant 4 2 (a) B.C,E.G
- 17. Auxiliary Feedwater Flow 2 per steam generator B,C,E.G
- 18. RCS Subcooling Margin Monitor 2 B.C.E.G
- 19. Steam Line Pressure 2 per steam generator B.C.E.G
- 20. Refueling Water Storage Tank Level 2 BCEG
- 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.ent
eRe&orner 3.6.7 3.6 CONTAINMENT SYSTEMS LCO 3.6.7 Two hydrogen rcombiners shall be OPERABLE.
APPLIC TY: MODE and 2.
AC NS , -
COND/10N REQUIRED ACTI/N COMPLETION TIJE A. One drogen A.1 -NOT-----------
re iner inoperable. LCO 3.0.4 is ot applicable.
Restore ydrogen 30 days recomb er to OPERABLE status.
f B. Required Action and B.1 Be MODE 3. 6 /3urs associated Completion/
Time not met. /
k I I I McGuire Units I and 2 3.6.7-1 Amendment Nos& sZ
Hydrogen Recombiners 3.6.7 RVEILLANCE REQUIREMENTS SURVEILLANCE FREQUNCY SR 3.6.7. Perform a system functional test for each hydrogen 18 moths ecombiner.
SR 3.6.7.2 Vis~ examine each hydrogen recombiner enclosure , 18 months and ve tere is no evidence of abnormal conditions.
SR 3.6.7.3 Perform a resa nce to ground test for each heat 18 months phase.
Mcfar Ui 18 M ure Units 1 and 2 3.6.7-2 Amendment Nos. 184/1
PAM Instrumentation B 3.3.3 BASES LCO (continued)
Two channels of wide range containment pressure are required OPERABLE.
- 9. Containment Atmosphere Radiation (HiOh 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. (vrqnM ntr Hydrogen onitors are pr ided to detec high hydrogen concentr ion conditions at represent potential for conta' ment breach !rom a hydroge explosion. T is variable is also i ortant in ye ying the adequcy of mitigati actions.
T0o channels of drogen moniors are re uired OP RABLE.
- 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.
PAM Instrumentation B 3.3.3 BASES ACTIONS (continued) discusses the results of the root cause evaluation of the inoperability and identifies proposed restorative actions. This action is appropriate in lieu of a shutdown requirement since alternative actions are identified before loss of functional capability, and given the likelihood of unit conditions that would require information provided by this instrumentation.
D.1 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 . _
l odton apies wh/ two hy ro n monitor gfannels are i perable.
Requir Action F.1 r uires resto ng one hydr gen monitor annel to OPE BLE status ithin 72 hou . The 72 h r Completio Time is rea nable based n the low p bability that n accident sing core da age would cur during Its time.
McGuire Units 1 and 2 B 3.3.3-12 Revision No.
PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)
G.1 and G.2 If the Required Action and associated Completion Time of Conditions DX r Ezare 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
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.
H.1 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 McGuire Units 1 and 2 B 3.3.3-13 Revision No. 5
PAM Instrumentation B 3.3.3 BASES SURVEILLANCE REQUIREMENTS (continued) similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar unit instruments located throughout the unit.
Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. If the channels are within the criteria, it is an indication that the channels are OPERABLE.
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. r SR 3.3.3.2 /
ACANLCALIBRATI N is ormed qzry 92 days 0 )he Hydron Monitor chnnels. CHA NEL CALIBRATI N is a complet check of t e instrument loop, includig the sensor usi hydrogen gas ixtures to obtain ibration poi s at 0 volume per ent (v/o) and 9 /0 hydrog The t t verifies that he channel resp ds to measure parameter ith the cessary ran and accuracy. T e Frequency is/ased on erating ex rience assocj ted with these m itors.
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 McGuire Units 1 and 2 B 3.3.3-14 Revision No.
<.7 B 3.6 CONTAINMENT SYSTEMS B 3.6.7 BA KGROldi The function of th/hydrogen recombiners is 90eliminate the po ent al breach of conta' ment due to a hydrogen o ygn reaction. /
Per 10 CFR0.44, "Standards for Corn ustible Gas Control Syems in Light-Wat -Cooled Reactors" (Ref. , and GDC 41, 'Containp ent I Atmospere Cleanup' (Ref. 2), hyd gen recombiners are r uired to lel, reducthe hydrogen concentrati in the containment foll ing a loss of 4e, coolnt accident (LOCA). The combiners accomplish s by
.re mbining hydrogen and o gen to form water vapor The vapor mains in containment, th eliminating any discharge to the environment. The hydro n recombiners are manally initiated since flammable limits would ot be reached until sev al days after a Design Basis Accident (DB /
Two 100% capaiy independent hydroge ecombiner systems a provided. Ea consists of controls locaI d outside containmen /n an area not ex sed to the post LOCA en ironment, a power sup y and a recombing Recombination is acco plished by heating a h rogen air mixture ove 11 50 0F. The resulti g water vapor and disc arge gases are c led prior to discharge fro the recombiner. A sin e recombiner is able of maintaining the hy rogen concentration i ontainment b ow the 4.0 volume percent fo) flammability limit. wo recombiners re provided to meet the re irement for redundan and independence.
Each recombiner is power d from a separate Engjfeered Safety Features bus, and is pro ded with a separate p er panel and control panel.
APPLICA E The hydrogen rec mbiners provide for t capability of controllin e SAFETY ANALYSES bulk hydrogen c ncentration in contain ent to less than the lowIr flammable co entration of 4.0 vfo fo wing a DBA. This con ol would prevent a co ainment wide hydrog burn, thus ensuring t pressure and temper ture assumed in the Ialyses are not exceed . The limiting DBA relay e to hydrogen generaion is a LOCA. Hydroge may accum Lte in containment foil ing a LOCA as a resu of:
- a. A metal steam reacti between the zirconiu fuel rod cladding and the reactor coo nt; McGuire Units 1 and 2 B 3.6.7-1 Revision No/
Hydrogen Recombiner, 133.7
\IASES-/
APP CABLE SAFETY ANALYSES (continued)
- c. Hydrogen in the RCS at the time of the LOCA (i.e hydrogen dissolved in the reactor coolant and hydrogen g in the pressurizer vapor space); or
- d. Corrosion of metals exposed to containme spray and Emergency ore Cooling System solutions.
To evaluat he potential for hydrogen accu ulation in containment following a LUCA, the hydrogen generatio as a function of time following the initiation of e accident is calculate Conservative assumptions recommended ference 3 ar o maximize the amount of hydrogen calculbyen 3 Based on the conservat e ass ptions used to calculate the hydrogen concentration versus time ft a LOCA, the hydrogen concentration increases at different rates epending on the region of the containment being measured. The inif ti of the Air Return System and Hydrogen Skimmer System along ith th ydrogen recombiners will maintain the hydrogen concentrati in the primary containment below flammability limits.
The hydrogen r ombiners are design such that, with the conservatively Iculated hydrogen gene tion rates, a single recombiner is capable o imiting the peak hydrogen co centration in containment to less than 0 v/o (Ref. 3).
The h rogen recombiners satisfy Criterion 3 of 0 CFR 50.36 (Ref. 4).
LCO o hydrogen recombiners must be OPERABLE. T s ensures operation of at least one hydrogen recombiner in the ent of a worst case single active failure.
Operation with at least one hydrogen recombiner ensures at the post LOCA hydrogen concentration can be prevented from exce ding the flammability limit.
APPL ILITY In MODES 1 and 2, two hydrogen recombiners are required to c trol the hydrogen concentration within containment below its flammability it of 4.0 vo following.a LOCA, assuming a worst case single failure.
/McGuire Units 1 and 2 B 3.6.7-2 Revision No.
Hydrogen Recombiner B 3..7 SES AP ICABILITY (continued)
In MODES 3 and 4, both the hydrogen production rate and th total hydrogen produced after a LOCA would be less than that c culated for the DBA LOCA. Also, because of the limited time in these ODES, the probability of an accident requiring the hydrogen recomb ers is low.
Therefore, the hydrogen recombiners are not required=iMODE 3 or 4.
In MODES 5 and 6, the probability and consequenc of a LOCA are low, due to the pressure and temperature limitations in ese MODES.
erefore, hydrogen recombiners are not requir in these MODES.
ACTIONS A.1 With one ntainment hydrogen reco in er inoperable, the inoperable recombiner ust be restored to OPE BLE status within 30 days. In this condition, e remaining OPER LE hydrogen recombiner is
- 9j&k} adequate to perin the hydrogen ontrol function. However, the overall reliability is reduce because a si gle failure in the OPERABLE recombiner could re It in redu d hydrogen control capability. The 30 day Completion Ti is ba ed on the availability of the other hydrogen recombiner, the small pr a lity of a LOCA occurring (that would generate an amount of hy ogen that exceeds the flammability limit), and the amount of time avail le fter a LOCA (should one occur) for operator action to prevyt hy1 gen accumulation from exceeding the flammability limit.
Required Action has been modi d by a Note that states the provisions of LC 3.0.4 are not appli ble. As a result, a MODE change is allowed wh one recombiner is inop able. This allowance is based on the avail ility of the other hydrogen r ombiner, the small probability of a LOC ccurring (that would generate amount of hydrogen that exceeds e flammability limit), and the amo t of time available after a LOCA should one occur) for operator action t revent hydrogen acc:ulation from exceeding the flammability Ii .
B.\
If the inoperable hydrogen recombiner(s) cannot be rest ed to OPERABLE status within the required Completion Time, t plant must be brought to a MODE in which the LCO does not apply. T achieve this status, the plant must be brought to at least MODE 3 within ours. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an o erly manner and without challenging plant systems.
Guire Units 1 and 2 B 3.6.7-3 Revision No
Hydrogen Recombined/
B 32 Y SES SURV LANCE SR 3.6.7.1 REQUIR ENTS Performance of a system functional test for each hydrogen combiner ensures the recombiners are operational and can attain an sustain the temperature necessary for hydrogen recombination. In rticular, this SR verifies that the minimum heater sheath temperature in eases to
\ 7000 F in < 90 minutes. After reaching 7000F, the p er is increased to aximum power (not to exceed maximum rated po r) for approximately 2 futes and power is verified to be 2 60 kW.
n lIndus operating experience has shown that ese components usually e pass th Surveillance when performed at the 8 month Frequency.
Therefor the Frequency was concluded t be acceptable from a
~fT5 / ' D reliability s ndpoint.
pi 77 r Ir--
SR 3.6.7.2 cc '&
This SR ensures there are no p ysical problems that could affect recombiner operati. Since ye recombiners are mechanically passive, they are not subject mecanical failure. The only credible failure involves loose wiring s ctural connections, deposits of foreign materials, etc.
A visual inspection iuffic nt to determine abnormal conditions that could cause such ilures. e 18 month Frequency for this SR was developed cons .ering the inc ence of hydrogen recombiners failing the SR in the pas s low.
SR 3.6 .3 Thi SR requires performance of a resist ce to ground test for each h ater phase to ensure that there are no dectable grounds in any eater phase. This SR should be performed ollowing SR 3.6.7.1. This is accomplished by verifying that the resistanc to ground for any heater phase is 2 10,000 ohms.
The 18 month Frequency for this Surveillance was d eloped considering the incidence of hydrogen recombiners failing the SR i he past is low.
/'Guire Units 1 and 2 B 3.6.7-4 Revision No
Hydrogen Recombiner B 3,.7
-NCES 1. 10 CFR 50.44.
- 3. UFSAR Section 6.2.
10 CFR 50.36, Technical Specifications, 2)(ii).
/(L
<$V - A IcGuire Units 1 and 2 B 3.6.7-5 Revision No.
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 accumulatio- from exceeding the flammability limit, and the availability of theLdadgn 1 9Hydrogen Mitigation System.
Required Action A.1 has been modified by a Note that states the provisions of LCO 3.0.4 are not applicable. As a result, a MODE change is allowed when one HSS train is inoperable. This allowance 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), and the amount of time available after a LOCA or SLB (should one occur) for operator action to prevent hydrogen accumulation from exceeding the flammability limit.
B.1 If an inoperable 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 <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 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 1 and 2 B 3.6.8-3 Revision No./
HMS B 3.6.9 BASES BACKGROUND (continued) that local pockets of hydrogen at increased concentrations would bum 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 burn 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 los f c t accident (LOCA).fe hyrge c~~wirtor~utrg f~ri D lf}
Lr~coMrxine s.l The hy~droge-n ~Ignitorsktve)6erhave be-en shfown 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.
McGuire Units 1 and 2 B 3.6.9-2 Revision No/
ATTACHMENT 3a Oconee Nuclear Station Units 1, 2, and 3 Revised (Clean) Technical Specifications and Bases Pages*
- Reprinted pages will be provided prior to issuance of the approved amendment.
ATTACHMENT 3b McGuire Nuclear Station Units 1 and 2 Revised (Clean) Technical Specifications and Bases Pages*
- Reprinted pages will be provided prior to issuance of the approved amendment.