Text

Sequoyah, Units 1 & 2, Revisions to the Technical Requirements Manual and Specification Bases
	ML13193A039
Person / Time
Site:	Sequoyah
Issue date:	07/05/2013
From:	Shea J W; Tennessee Valley Authority
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML13193A039 (114)
	v • d • e

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402July 5, 201310 CFR 50.410 CFR 50.71(e)ATTN: Document Control DeskU.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Sequoyah Nuclear Plant, Units 1 and 2Facility Operating License Nos. DPR-77 and DPR-79NRC Docket Nos. 50-327 and 50-328

Subject:

Revisions to the Sequoyah Nuclear Plant Technical Requirements Manual and Units I and 2 Technical Specification Bases

References:

1. NRC Letter to TVA, "Issuance of Exemption to 10 CFR 71(e)(4) for theSequoyah Nuclear Plant, Units 1 and 2 (TAC Nos. MA0646 andMA0647),"

dated March 9, 19982. TVA Letter to NRC, "Revisions to the Sequoyah Nuclear Plant Technical Requirements Manual and Units 1 and 2, Technical Specification Bases,"dated December 16, 2011Pursuant to 10 CFR 50.71(e) and the Reference 1 letter, updates to the Sequoyah NuclearPlant (SQN) Updated Final Safety Analysis Report (UFSAR) for both Units 1 and 2 are to besubmitted within six months after each refueling outage, not to exceed 24 months betweensuccessive revisions.

The SQN Technical Requirements Manual (TRM) is incorporated byreference into the SQN UFSAR. In addition, SQN Technical Specification 6.8.4.j, "Technical Specification (TS) Bases Control Program,"

requires changes to the SQN TS Bases to besubmitted in accordance with 10 CFR 50.71(e).

This letter provides the required updates tothe SQN TRM and TS Bases since the previous update submitted via the Reference 2Letter. The last Unit 2 refueling outage ended on January 6, 2013, and as such, theseupdates are required by July 5, 2013. The enclosure to this letter provides a description ofthe TRM and TS Bases revisions with attachments of the updated pages, respectively.

Printed on recycled paper U.S. Nuclear Regulatory Commission Page 2July 5, 2013There are no commitments contained in this letter. If you have any questions, pleasecontact Michael McBrearty at (423) 843-7170.

I certify that I am duly authorized by TVA, and that, to the best of my knowledge and belief,the information contained herein accurately presents changes made since the previoussubmittal, necessary to reflect information and analyses submitted to the Commission orprepared pursuant to Commission requirements.

Respectf lly,eesident, Nuclear Licensing

Enclosure:

Description of Revisions for the Sequoyah Nuclear Plant (SQN), Technical Requirements Manual and SQN, Units 1 and 2 Technical Specification Basescc (Enclosure):

NRC Regional Administrator-Region IINRC Senior Resident Inspector

-Sequoyah Nuclear Plant ENCLOSURE DESCRIPTION OF REVISIONS FOR THE SEQUOYAH NUCLEAR PLANT (SQN),TECHNICAL REQUIREMENTS MANUAL ANDSQN, UNITS I AND 2 TECHNICAL SPECIFICATION BASESTechnical Requirements Manual Revisions Technical Requirements Manual (TRM) Revision 47 was approved on September 27, 2012, andimplemented on October 5, 2012. A change was made to TR 3.1.2.2, "Flow Paths -Operating,"

and TR 3.1.2.4, "Charging Pumps -Operating,"

to allow an operational provision similar to thetechnical specifications (TSs) allowance for temporarily disabling one half of the boron injection function of the Chemical and Volume Control System (i.e., one charging pump and associated flow path) to support transition between Modes 3 and 4. Provisions are provided in the TSs thatallow the Emergency Core Cooling System (ECCS) pumps to be made incapable of injecting, inMode 3, for a limited amount of time or system conditions to support Low Temperature OverPressure Protection (LTOP) System operations.

This provision prevents TS non-compliance when entering into and out of Mode 3 when two charging pumps are required to be operable.

This change aligns the TRM to be consistent with the TSs for support of LTOP Systemoperations.

On May 15, 2007, TRM Revision 37 was reported to NRC. TRM Revision 37 was in support ofSQN TS Amendment Nos. 305 for Unit 1 and 295 for Unit 2. A typographical error has beenidentified involving symbol characters with the issued page for TR 3.3.3.2, "Moveble IncoreDetectors."

The corrected page is submitted herein without change to the revision bar.Technical Specification Bases Revisions Revision 38 to the SQN, Units 1 and 2 Technical Specification (TS) Bases was approved onMarch 24, 2012, and implemented on March 26, 2012. The revision was in light ofTS Change 07-05, "Emergency Core Cooling Systems (ECCS)" for SQN, Units 1 and 2,andassociated with TS Amendment Nos. 326 and 319 approved on January 28, 2010. TS BasesSection 3.5.3, "ECCS -Shutdown,"

was revised to support primary and secondary residual heatremoval check valve testing during Mode 4 operation.

The changes differentiated TS BasesSection 3.5.2, "ECCS -Operating,"

Mode 1 through 3 safety analysis conditions from Mode 4conditions, defines the necessary ECCS operation and flow paths, and added a reference.

Revision 39 to the SQN Unit 1 TS Bases was approved on October 5, 2012, and implemented on October 25, 2012. This revision was in concert with TS Amendment No. 330. LimitingCondition for Operation (LCO), 3.7.5 "Ultimate Heat Sink," was amended to supportmaintenance activities during the Unit 2 refueling outage No. 18. The TS Bases were changedto identify additional LCO restrictions with respect to maximum average Essential Raw CoolingWater (ERCW) system supply header water temperature during large heavy load lifts performed to support the refueling outage.Revision 40 to the Unit 1 and Revision 39 to the Unit 2 TS Bases were approved on October 10,2012. Unit 2 was implemented on November 28, 2012 during its refueling outage. Unit 1 willimplement this revision during its next refueling outage in the Fall of 2013; therefore is notprovided in this update. These TS Bases revisions are associated with TS Amendment Nos.331 and 324 for approved TS Change 11-07, "Application to Modify Technical Specifications forUse of AREVA Advanced W17 HTP Fuel." This change affected TS Bases Section 2.1, "SafetyE1-1 Limits,"

and Section 3/4.2.5, "DNB Parameters,"

as it provided clarifications associated with theevaluation methodology for the new fuel design.Revision 40 to the Unit 2 TS Bases was approved on October 5, 2012, and implemented onNovember 2, 2012. This TS Bases revision to Section 3/4.4.5, "Reactor Coolant System,"

andSection 3/4.4.6.2, "Operation Leakage,"

was associated with replacement of the Unit 2 steamgenerators.

The revision is associated with TS Amendment No. 323, in which previously approved steam generator inspections, specific repair criteria and reporting requirements hadbeen modified or removed.Revision 41 to the SQN, Units 1 and 2 Bases was approved on December 21, 2012, andimplemented on December 27, 2012. This revision incorporated changes to the Bases forSpecification 3.8.1, "A. C. Sources,"

to describe a new surveillance requirement approved underTS Amendment Nos. 332 and 325 for Units 1 and 2, respectively.

Other changes to the TSBases section include example descriptions of offsite power configurations that would meet therequirements of TS LCO 3.8.1.1.a.

Revision 42 to the SQN, Units 1 and 2 Bases was approved on March 5, 2013, andimplemented on March 25, 2013. TS Bases Section 3/4.3.3.7, "Accident Monitoring Instrumentation,"

was revised.

Statements describing accident monitoring instrumentation, specifically the SQN hydrogen monitoring channels were deleted.

This change was associated with TS Amendment Nos. 296 and 286 for Units 1 and 2, respectively, which eliminated therequirements for hydrogen recombiners and hydrogen monitoring.

Also, enclosed is a typographical correction to TS Bases Table B 3/4.4-1, SQN Unit 1 ReactorVessel Toughness Data with no indication of a revision bar. This change corrects the value ofnickel in the weld material of the reactor vessel.Attachments:

1. Sequoyah Nuclear Plant, Technical Requirements Manual -Changed Pages2. Sequoyah Nuclear Plant, Unit 1, Technical Specification Bases -Changed Pages3. Sequoyah Nuclear Plant, Unit 2, Technical Specification Bases -Changed PagesE1-2

,1ATTACHMENT ISEQUOYAH NUCLEAR PLANTTECHNICAL REQUIREMENTS MANUALCHANGED PAGESTRM Affected PagesEPL-1EPL-2EPL-5EPL-8Index Page III3/4 1-3 through 3/4 1-133/4 3-2B 3/4 1-2B 3/4 1-3 SEQUOYAH NUCLEAR PLANT UNITS 1 AND 2TECHNICAL REQUIREMENTS MANUALEFFECTIVE PAGE LISTINGPage RevisionIndex Page I 09/28/03Index Page II 02/02/98Index Page III 09/27/12Index Page IV 01/20/06Index Page V 01/20/06Index Page VI 01/20/06Index Page VII 02/02/98Index Page VIII 02/02/981-1 02/02/981-2 05/18/091-3 09/28/031-4 07/19/021-5 07/25/021-6 02/02/981-7 02/02/981-8 02/02/983/4 0-1 05/27/053/4 0-2 05/27/053/4 0-3 07/25/063/4 0-4 07/25/063/4 1-1 01/04/013/4 1-2 10/12/05EPL-1September 27, 2012 SEQUOYAH NUCLEAR PLANT UNITS 1 AND 2TECHNICAL REQUIREMENTS MANUALEFFECTIVE PAGE LISTINGPaqe Revision3/4 1-3 09/27/123/4 1-4 09/27/123/4 1-5 09/27/123/4 1-6 09/27/123/4 1-7 09/27/123/4 1-9 09/27/123/4 1-10 09/27/123/4 1-11 09/27/123/4 1-12 09/27/123/4 1-13 09/27/123/4 3-1 01/20/063/4 3-2 01/20/063/4 3-3 01/20/063/4 3-4 01/20/063/4 3-5 01/20/063/4 3-6 10/17/063/4 3-7 04/26/063/4 3-8 04/26/063/4 3-9 01/20/063/4 3-10 01/20/063/44-1 01/20/063/4 4-2 01/20/063/4 4 01/20/06EPL-2September 27, 2012 SEQUOYAH NUCLEAR PLANT UNITS 1 AND 2TECHNICAL REQUIREMENTS MANUALEFFECTIVE PAGE LISTINGPage RevisionB 3/4 1-1 01/04/01B 3/4 1-2 Through B 3/4 1-3 09/27/12B 3/4 1-4 Through B 3/4 1-6 01/04/01B 3/4 3-1 01/20/06B 3/4 3-2 01/20/06B 3/4 3-3 01/20/06B 3/4 3-4 01/20/06B 3/4 3-5 01/20/06B 3/4 3-6 01/20/06B 3/4 3-7 01/20/06B 3/4 3-8 01/20/06B 3/4 3-9 01/20/06B 3/4 3-10 01/20/06B 3/4 3-11 01/20/06B 3/4 3-12 01/20/06B 3/4 3-13 01/20/06B 3/4 3-14 01/20/06B 3/4 4-1 01/20/06B 3/4 4-2 01/20/06B 3/4 4-3 01/20/06EPL-5September 27, 2012 SEQUOYAH NUCLEAR PLANT UNITS 1 AND 2TECHNICAL REQUIREMENTS MANUALREVISION LISTINGRevision DateInitial Issue, Revision 0 02/02/98Revision 1 10/01/98Revision 2 02/12/99Revision 3 03/18/99Revision 4 09/14/99Revision 5 10/24/99Revision 6 09/29/99Revision 7 12/09/99Revision 8 03/23/00Revision 9 06/02/00Revision 10 06/13/00Revision 11 06/15/00Revision 12 11/09/00Revision 13 01/04/01Revision 14 04/05/01Revision 15 07/11/01Revision 16 04/05/02Revision 17 03/27/02Revision 18 07/19/02Revision 19 07/25/02Revision 20 10/11/02Revision 21 03/06/03Revision 22 08/11/03Revision 23 09/14/03Revision 24 09/28/03Revision 25 10/31/03Revision 26 09/26/03Revision 27 09/26/03Revision 28 05/15/04Revision 29 10/13/04Revision 30 10/13/04Revision 31 04/22/05Revision 32 05/27/05Revision 33 06/20/05Revision 34 06/24/05Revision 35 10/12/05Revision 36 10/19/05Revision 37 01/20/06Revision 38 03/08/06Revision 39 03/17/06Revision 40 04/26/06Revision 41 07/25/06Revision 42 09/15/06Revision 43 10/17/06Revision 44 11/14/06Revision 45 05/18/09Revision 46 11/29110Revision 47 09/27/12EPL-8September 27, 2012 INDEXTECHNICAL REQUIREMENTS SECTION PAGET R 3/4 .0 A P P LIC A B ILIT Y .................................................................................................................

3/4 0-1TR 3/4.1 REACTIVITY CONTROL SYSTEMST R 3/4.1.1 (N o current requirem ents) ..................................................................................................

3/4 1-1TR 3/4.1.2 BORATION SYSTEMSTR 3/4.1.2.1 FLOW PATHS -SHUTDOW N ...........................................................................

3/4 1-2TR 3/4.1.2.2 FLOW PATHS -O PERATING

...........................................................................

3/4 1-3TR 3/4.1.2.3 CHARGING PUMP -SHUTDOWN

....................................................................

3/4 1-5TR 3/4.1.2.4 CHARGING PUMPS -OPERATING

.................................................................

3/4 1-6TR 3/4.1.2.5 BORATED WATER SOURCES -SHUTDOWN

................................................

3/4 1-7TR 3/4.1.2.6 BORATED WATER SOURCES -OPERATING

................................................

3/4 1-9TR 3/4.1.3.1 Through TR 3/4.1.3.2 (No current requirements)

.........................................................

3/4 1-12TR 3/4.1.3.3 POSITION INDICATION SYSTEM -SHUTDOWN

......................................................

3/4 1-13TR 3/4.2 POWER DISTRIBUTION LIMITSNo current requirements TR 3/4.3 INSTRUMENTATION TR 3/4.3.1 Through TR 3/4.3.3.1 (No current requirements)

..............................................................

3/4 3-1TR 3/4.3.3 MONITORING INSTRUMENTATION TR 3/4.3.3.2 MOVABLE INCORE DETECTORS

...................................................................

3/4 3-2TR 3/4.3.3.3 SEISMIC INSTRUMENTATION

........................................................................

3/4 3-3TR 3/4.3.3.4 METEOROLOGICAL INSTRUMENTATION

.....................................................

3/4 3-6TR 3/4.3.3.5 Through TR 3/4.3.3.14 (No current requirements)

...........................................

3/4 3-9TR 3/4.3.3.15 PLANT CALORIMETRIC MEASURMENT

....................................................

3/4 3-10TR 3/4.4 REACTOR COOLANT SYSTEMTR 3/4.4.1 Through TR 3/4 4.6 (No current requirements)

.................................................................

3/4 4-1T R 3/4 4 .7 C H E M IS T R Y ......................................................................................................................

3/4 4-2TR 3/4.4.8 Through TR 3/4 4.9.1 (No current requirements)

..............................................................

3/4 4-5TR 3/4 4.9.2 PRESSURIZER TEMPERATURE LIMITS .....................................................................

3/4 4-6T R 3/4.4.10 (N o current requirem ents) ................................................................................................

3/4 4-7TR 3/4 4.11 REACTOR COOLANT SYSTEM HEAD VENTS .............................................................

3/4 4-8TR 3/4.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)No current requirements SEQUOYAH

-UNITS 1 AND 2 III September 27, 2012TECHNICAL REQUIREMENTS Revision Nos. 1, 3-5, 8-13, 16, 17, 20, 23,29,30,31,37,47 REACTIVITY CONTROL SYSTEMSFLOW PATHS -OPERATING LIMITING CONDITION FOR OPERATION TR 3.1.2.2 At least two of the following three boron injection flow paths shall be OPERABLE:

a. The flow path from the boric acid tanks via a boric acid transfer pump and a chargingpump to the Reactor Coolant System.b. Two flow paths from the refueling water storage tank via charging pumps to the ReactorCoolant System.------------------

NNOT----------------

In MODE 3, one charging pump may be made incapable of injecting to support transition into or from theAPPLICABILITY of Technical Specification LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP) System,"

for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or until the temperature of all RCS cold legs exceeds LTOP armingtemperature (350°F) specified in the Pressure and Temperature Limits Report (PTLR) plus 250F,whichever comes first.APPLICABILITY:

MODES 1, 2, and 3.ACTION:With only one of the above required boron injection flow paths to the Reactor Coolant SystemOPERABLE, restore at least two boron injection flow paths to the Reactor Coolant System to OPERABLEstatus within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY and borated to a SHUTDOWN MARGINequivalent to at least 1% delta k/k at 200OF within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; restore at least two flow paths toOPERABLE status within the next 7 days or be in HOT SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .SURVEILLANCE REQUIREMENTS TR 4.1.2.2 At least two of the above required flow paths shall be demonstrated OPERABLE:

a. At least once per 7 days by verifying that the temperature of the areas containing flowpath components from the boric acid tanks to the blending tee is greater than or equal to630F when it is a required water source.b. Whenever the area temperature(s) is(are) less than 630F and the boric acid tank is arequired water source, the solution temperature in the flow path components from theboric acid tank must be measured to be greater than or equal to 630F within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months andevery 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter until the area temperature(s) has(have) returned to greater thanor equal to 630F.SEQUOYAH

-UNITS 1 AND 2 3/4 1-3 September 27, 2012TECHNICAL REQUIREMENTS Revision Nos. 13, 46, 47 REACTIVITY CONTROL SYSTEMSFLOW PATHS -OPERATING SURVEILLANCE REQUIREMENTS (continued)

c. At least once per 31 days by verifying that each valve (manual, power operated orautomatic) in the flow path that is not locked, sealed, or otherwise secured in position, isin its correct position.

d. At least once per 18 months during shutdown by verifying that each automatic valve inthe flow path actuates to its correct position on a safety injection test signal.e. At least once per 18 months by verifying that the flow path required by TR 3.1.2.2adelivers at least 35 gpm to the Reactor Coolant System.SEQUOYAH

-UNITS 1 AND 2TECHNICAL REQUIREMENTS 3/4 1-4September 27, 2012Revision Nos. 13, 46 REACTIVITY CONTROL SYSTEMSCHARGING PUMP -SHUTDOWNLIMITING CONDITION FOR OPERATION TR 3.1.2.3 One charging pump in the boron injection flow path required by TR 3.1.2.1 shall beOPERABLE and capable of being powered from an OPERABLE shutdown board.APPLICABILITY:

MODES 4, 5 and 6.ACTION:MODE 4 -With no charging pump OPERABLE, suspend operations that would cause introduction ofcoolant into the RCS with boron concentration less than required to meet SDM of Technical Specification LCO 3.1.1.1 and restore one changing pump as soon as possible.

MODE 5 -With no charging pump OPERABLE, suspend operations that would cause introduction ofcoolant into the RCS with boron concentration less than required to meet SDM of Technical Specification LCO 3.1.1.2.MODE 6 -With no charging pump OPERABLE, suspend all operations involving CORE ALTERATIONS and suspend operations that would cause introduction of coolant into the RCS with boronconcentration less than required to meet Technical Specification LCO 3.9.1.SURVEILLANCE REQUIREMENTS TR 4.1.2.3 The above required charging pump shall be demonstrated OPERABLE by verifying, that onrecirculation flow, the pump develops a discharge pressure of greater than or equal to 2400 psig whentested pursuant to TR 4.0.5.SEQUOYAH

-UNITS I AND 2TECHNICAL REQUIREMENTS 3/4 1-5September 27, 2012Revision Nos. 13, 25, 35 REACTIVITY CONTROL SYSTEMSCHARGING PUMPS -OPERATING LIMITING CONDITION FOR OPERATION TR 3.1.2.4 At least two charging pumps shall be OPERABLE.

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

In MODE 3, one charging pump may be made incapable of injecting to support transition into or from theAPPLICABILITY of Technical Specification LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP) System,"

for up to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or until the temperature of all RCS cold legs exceeds LTOP armingtemperature (3500F) specified in the Pressure and Temperature Limits Report (PTLR) plus 25°F,whichever comes first.APPLICABILITY:

MODES 1, 2, and 3.ACTION:With only one charging pump OPERABLE, restore at least two charging pumps to OPERABLE statuswithin 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months or be in at least HOT STANDBY and borated to a SHUTDOWN MARGIN equivalent to atleast 1% delta k/k at 200OF within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ; restore at least two charging pumps to OPERABLEstatus within the next 7 days or be in HOT SHUTDOWN within the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .SURVEILLANCE REQUIREMENTS TR 4.1.2.4 At least two charging pumps shall be demonstrated OPERABLE by verifying, that onrecirculation flow, each pump develops a discharge pressure of greater than or equal to 2400 psig whentested pursuant to TR 4.0.5.SEQUOYAH

-UNITS 1 AND 2TECHNICAL REQUIREMENTS 3/4 1-6September 27, 2012Revision Nos. 13, 47 REACTIVITY CONTROL SYSTEMSBORATED WATER SOURCES -SHUTDOWNLIMITING CONDITION FOR OPERATION TR 3.1.2.5 As a minimum, one of the following borated water sources shall be OPERABLE:

a. A boric acid storage system with:1. A minimum contained borated water volume of 6400 gallons,2. Between 6120 and 6990 ppm of boron, and3. A minimum solution temperature of 630F.b. The refueling water storage tank with:1. A minimum contained borated water volume of 55,000 gallons,2. A minimum boron concentration of 2500 ppm, and3. A minimum solution temperature of 600F.APPLICABILITY:

MODES 4, 5 and 6.ACTION:MODE 4 -With no borated water source OPERABLE, suspend operations that would cause introduction of coolant into the RCS with boron concentration less than required to meet SDM of Technical Specification LCO 3.1.1.1.MODE 5 -With no borated water source OPERABLE, suspend operations that would, cause introduction of coolant into the RCS with boron concentration less than required to meet SDM of Technical Specification LCO 3.1.1.2.MODE 6 -With no borated water source OPERABLE, suspend all operations involving COREALTERATIONS and suspend operations that would cause introduction of coolant into the RCSwith boron concentration less than required to meet Technical Specification LCO 3.9.1.SURVEILLANCE REQUIREMENTS TR 4.1.2.5 The above required borated water source shall be demonstrated OPERABLE:

a. For the boric acid storage system, when it is the source of borated water by:1. Verifying the boron concentration at least once per 7 days,2. Verifying the borated water volume at least once per 7 days, andSEQUOYAH

-UNITS 1 AND 2TECHNICAL REQUIREMENTS 3/4 1-7September 27, 2012Revision Nos. 13, 25, 35, 36 REACTIVITY CONTROL SYSTEMSSURVEILLANCE REQUIREMENTS (Continued)

3. Verifying the boric acid storage tank solution temperature is greater than or equalto 630F at least once per 7 days by verifying the area temperature to be greaterthan or equal to 630F, or4. When the boric acid tank area temperature is less than 630F and the boric acidstorage system being used as the source of borated water, within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months andevery 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter, verify the boric acid tank solution temperature to begreater than or equal to 630F until the boric acid tank area temperature hasreturned to greater than or equal to 630F.b. For the refueling water storage tank by:1. Verifying the boron concentration at least once per 7 days,2. Verifying the borated water volume at least once per 7 days, and3. Verifying the solution temperature at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months while in Mode 4 orwhile in Modes 5 or 6 when it is the source of borated water.SEQUOYAH

-UNITS 1 AND 2TECHNICAL REQUIREMENTS 3/4 1-8September 27, 2012Revision Nos. 13 REACTIVITY CONTROL SYSTEMSBORATED WATER SOURCES -OPERATING LIMITING CONDITION FOR OPERATION TR 3,1.2.6 As a minimum, the following borated water source(s) shall be OPERABLE as required byTR 3.1.2.2:a. A boric acid storage system with:1. A contained volume of borated water in accordance with Figure 3.1.2.6,2. A boron concentration in accordance with Figure 3.1.2.6, and3. A minimum solution temperature of 630F.b. The refueling water storage tank with:1. A contained borated water volume of between 370,000 and 375,000 gallons,2. Between 2500 and 2700 ppm of boron,3. A minimum solution temperature of 600F, and4. A maximum solution temperature of 1050F.APPLICABILITY:

MODES 1, 2, and 3.ACTION:a. With the boric acid storage system inoperable and being used as one of the aboverequired borated water sources, restore the storage system to OPERABLE status within72 hours or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and borated to aSHUTDOWN MARGIN equivalent to at least 1% delta k/k at 200°F; restore the boric acidstorage system to OPERABLE status within the next 7 days or be in HOT SHUTDOWNwithin the next 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .b. With the refueling water storage tank inoperable, restore the tank to OPERABLE statuswithin one hour or be in at least HOT STANDBY within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in COLDSHUTDOWN within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months .SEQUOYAH

-UNITS 1 AND 2 3/4 1-9 September 27, 2012TECHNICAL REQUIREMENTS Revision Nos. 13 REACTIVITY CONTROL SYSTEMSSURVEILLANCE REQUIREMENTS TR 4.1.2.6 Each borated water source shall be demonstrated OPERABLE:

a. For the boric acid storage system, when it is the source of borated water by:1. Verifying the boron concentration at least once per 7 days,2. Verifying the borated water volume at least once per 7 days, and3. Verifying the boric acid storage tank solution temperature is greater than or equal to630F at least once per 7 days by verifying the area temperature to be greater than orequal to 630F, or4. Whenever the boric acid tank area temperature is less than 630F and the boric acidstorage system being used as the source of borated water, within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and every24 hours thereafter, verify the boric acid tank solution temperature to be greater thanor equal to 630F until the boric acid tank area temperature has returned to greaterthan or equal to 630F.b. For the refueling water storage tank by:1. Verifying the boron concentration at least once per 7 days,2. Verifying the borated water volume at least once per 7 days, and3. Verifying the solution temperature at least once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .SEQUOYAH

-UNITS 1 AND 2TECHNICAL REQUIREMENTS 3/4 1-10September 27, 2012Revision Nos; 13, 33 TRM FIGURE 3.1.2.6 (Units 1 & 2)BORIC ACID TANK LIMITSBASED ON RWST BORON CONCENTRATION 110001050010000z0-j-j0w..J0zI-lC..00wl-0z[REGION OF ACCEPTABLE OPERATION

RWST 2500 ppmnB -----RWST = 2550 ppm BRWST = 2600 ppm BRWST 2650ppmBRWST 2700 ppmB6120 ppm (Minimum)

6990 ppm (Maximum) 9500900085007500-.[REGION OF UNACCEPTABLE OPERATION 7000 -I I I I I I I I i I I I IIndicated values include 1140 gal unusable volume and 800 gal for instrument error. II I I I I I I I650U ~fl* --6000 6100 6200 6300 6400 6500 6600 6700 6800 6900 7000 7100BORIC ACID TANK CONCENTRATION

-PPM BORONRWST Concentration

--4--2500 PPM --4--2550 PPM --X--2600 PPM 2650 PPM --,-2700 PPMSEQUOYAH

-UNITS 1 AND 2*TECHNICAL REQUIREMENTS 3/4E1-11September 27, 2012Revision Nos. 13, 26, 27 TR 3/4.1 REACTIVITY CONTROL SYSTEMSTR 3/4 1.3.1 No current requirements TR 3/4 1.3.2 No current reauirements SEQUOYAH

-UNITS 1 AND 2TECHNICAL REQUIREMENTS 3/4 1-12September 27, 2012Revision Nos. 13 REACTIVITY CONTROL SYSTEMSPOSITION INDICATION SYSTEM -SHUTDOWNLIMITING CONDITION FOR OPERATION TR 3.1.3.3 The group demand position indicator shall be OPERABLE and capable of determining within+/- 2 steps, the demand position for each shutdown or control rod not fully inserted.

APPLICABILITY:

MODES 3*, 4* and 5*.ACTION:With less than the above required group demand position indicator(s)

OPERABLE, immediately open thereactor trip system breakers.

SURVEILLANCE REQUIREMENTS TR 4.1.3.3 Each of the above required group demand position indicator(s) shall be determined to beOPERABLE by movement of the associated control rod at least 10 steps in any one direction at leastonce per 31 days.*With the reactor trip system breakers in the closed position.

SEQUOYAH

-UNITS 1 AND 2TECHNICAL REQUIREMENTS 3/4 1-13September 27, 2012Revision Nos. 13 INSTRUMENTATION MOVABLE INCORE DETECTORS LIMITING CONDITION FOR OPERATION TR 3.3.3.2 The movable incore detection system shall be OPERABLE with:a. At least 75% of the detector

thimbles,

b. A minimum of 2 detector thimbles per core quadrant, andc. Sufficient movable detectors, drive, and readout equipment to map these thimbles.

APPLICABILITY:

When the movable incore detection system is used for:a. Recalibration of the excore neutron flux detection system,b. Monitoring the QUADRANT POWER TILT RATIO, orc. Measurement of FN and FQ(Z).FAH an Q()ACTION:With the movable incore detection system inoperable, do not use the system for the above applicable monitoring or calibration functions.

The provisions of Specification TR 3.0.3 are not applicable.

SURVEILLANCE REQUIREMENTS TR 4.3.3.2 The movable incore detection system shall be demonstrated OPERABLE by normalizing eachdetector output when required for:a. Recalibration of the excore neutron flux detection system, orb. Monitoring the QUADRANT POWER TILT RATIO, orc. Measurement of FN and FQ(Z).FAH an Q()SEQUOYAH

-UNITS 1 AND 2 3/4 3-2 January 20, 2006TECHNICAL REQUIREMENTS Revision Nos. 37 REACTIVITY CONTROL SYSTEMSBASESTRB 3/4.1.2 BORATION SYSTEMSThe boron injection system ensures that negative reactivity control is available during each modeof facility operation.

The components required to perform this function include 1) borated water sources,2) charging pumps, 3) separate flow paths, 4) boric acid transfer pumps, and 5) an emergency powersupply from OPERABLE diesel generators.

With the RCS average temperature above 3500F, a minimum of two boron injection flow pathsare required to ensure single functional capability in the event an assumed failure renders one of the flowpaths inoperable.

The boration capability of either flow path is sufficient to provide a SHUTDOWNMARGIN from expected operating conditions of 1.6% delta k/k after xenon decay and cooldown to 2000F.The maximum expected boration capability requirement occurs at near EOL from full power peak xenonconditions and requires borated water from a boric acid tank in accordance with Figure 3.1.2.6, andadditional makeup from either: (1) the common boric acid tank and/or batching, or (2) a minimum of26,000 gallons of 2500 ppm borated water from the refueling water storage tank. With the refueling waterstorage tank as the only borated water source, a minimum of 57,000 gallons of 2500 ppm borated wateris required.

TR 3.1.2.4 and TR 3.1.2.2 are modified by a Note. Operation in MODE 3 with one charging pump madeincapable of injecting, in order to facilitate entry into or exit from the Applicability of Technical Specification LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP) System,"

is necessary forplants with an LTOP arming temperature at or near the MODE 3 boundary temperature of 3500F.Technical Specification LCO 3.4.12 requires that certain pumps be rendered incapable of injecting at andbelow the LTOP arming temperature.

When this temperature is at or near the MODE 3 boundarytemperature, time is needed to make a pump incapable of injecting prior to entering the LTOPApplicability, and provide time to restore the inoperable pump to OPERABLE status on exiting the LTOPApplicability.

The boric acid tanks, pumps, valves, and piping contain a boric acid solution concentration ofbetween 3.5% and 4.0% by weight. To ensure that the boric acid remains in solution, the air temperature is monitored in strategic locations.

By ensuring the air temperature remains at 630F or above, a 50Fmargin is provided to ensure the boron will not precipitate out. To provide operational flexibility, if thearea temperature should fall below the required value, the solution temperature (as determined by thepipe or tank wall temperature) will be monitored at an increased frequency to compensate for the lack ofsolution temperature alarm in the main control room.With the RCS temperature below 3500F, one injection system is acceptable without single failureconsideration on the basis of the stable reactivity condition of the reactor and the additional restrictions prohibiting CORE ALTERATIONS and operations involving positive reactivity additions that could result inloss of required SDM (Modes 4 or 5) or boron concentration (Mode 6) in the event the single injection system becomes inoperable.

Suspending positive reactivity additions that could result in failure to meetminimum SDM or boron concentration limit is required to assure continued safe operation.

Introduction ofcoolant inventory must be from sources that have a boron concentration greater than or equal to thatrequired in the RCS for minimum SDM or refueling boron concentration.

This may result in an overallreduction in RCS boron concentration but provides acceptable margin to maintaining subcritical operation.

Introduction of temperature changes including temperature increases when operating with apositive MTC must also be evaluated to ensure they do not result in a loss of required SDM.SEQUOYAH

-UNITS 1 AND 2 B 3/4 1-2 September 27, 2012TECHNICAL REQUIREMENTS Revision Nos. 13, 25, 35, 36, 47 REACTIVITY CONTROL SYSTEMSBASESThe boron capability required below 3500F, is sufficient to provide a SHUTDOWN MARGIN of1.6% delta k/k after xenon decay and cooldown from 350OF to 2000, and a SHUTDOWN MARGIN of 1%delta k/k after xenon decay and cooldown from 200OF to 1400F. This condition requires either 6400gallons of 6120 ppm borated water from the boric acid storage tanks or 13,400 gallons of 2500 ppmborated water from the refueling water storage tank.The contained water volume limits include allowance for water not available because of discharge line location and other physical characteristics.

The 6400 gallon limit in the boric acid tank for Modes 4,5, and 6 is based on 4,431 gallons required for shutdown margin, 1,140 gallons for the unusable volumein the heel of the tank, 800 gallons for instrument error, and an additional 29 gallons due to rounding up.The 55,000 gallon limit in the refueling water storage tank for modes 4, 5, and 6 is based upon 22,182gallons that is undetectable due to lower tap location, 19,197 gallons for instrument error, 13,400 gallonsrequired for shutdown margin, and an additional 221 gallons due to rounding up.The limits on contained water volume and boron concentration of the RWST also ensure a pHvalue of between 7.5 and 9.5 for the solution recirculated within containment after a LOCA. This pH bandminimizes the evolution of iodine and minimizes the effect of chloride and caustic stress corrosion onmechanical systems and components.

The OPERABILITY of one boron injection system during REFUELING ensures that this system isavailable for reactivity control while in MODE 6.SEQUOYAH

-UNITS 1 AND 2TECHNICAL REQUIREMENTS B 3/4 1-3September 27, 2012Revision Nos. 13, 36 ATTACHMENT 2SEQUOYAH NUCLEAR PLANT, UNIT ITECHNICAL SPECIFICATION BASESCHANGED PAGESTS Bases Affected PagesEPL Page 18EPL Page 20EPL Page 21EPL Page 22EPL Page 25EPL Page 26EPL Page 27EPL Page 28EPL Page 29EPL Page 30EPL Page 31EPL Page 32EPL Page 33EPL Page 34Index Page XIVB 3/4 3-3aB 3/4 4-12B 3/4 5-12B 3/4 5-13B 3/4 5-14B 3/4 5-15B 3/4 5-16B 3/4 5-17B 3/4 5-18B 3/4 5-19B 3/4 5-20B 3/4 7-4aB 3/4 7-4bB 3/4 8-1B 3/4 8-2B 3/4 8-3B 3/4 8-4B 3/4 8-5B 3/4 8-6B 3/4 8-7B 3/4 8-8B 3/4 8-9 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaqe RevisionB3/4 3-3 12/28/05B3/4 3-3a 03/05/13B3/4 3-4 08/12/97B3/4 3-5 through B3/4 3-9 09/14/06B3/4 4-1 03/09/05B3/4 4-2 06/16/06B3/4 4-2a 02/23/06B3/4 4-3 02/23/06B3/4 4-3a 05/18/06B3/4 4-3b 02/23/06B3/4 4-3c through B3/4 4-3d 05/18/0683/4 4-4 02/23/06B3/4 4-4a 02/23/06B3/4 4-4b 12/04/08B3/4 4-4c 12/04/08B3/4 4-4d 04/11/05B3/4 4-4e 12/04/08B3/4 4-4f 12/04/08B3/4 4-4g 05/18/06B3/4 4-4h 05/18/06B3/4 4-4i 02/23/0683/4 4-4j 02/23/06B3/4 4-4k 02/23/06B3/4 4-41 02/23/0683/4 4-4m 08/04/00B3/4 4-4n 08/04/00EPL-18March 5, 2013 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaqe RevisionB3/4 4-23 11/09/04B3/4 5-1 03/25/10B3/4 5-2 03/25/10B3/4 5-3 03/25/10B3/4 5-4 03/25/10B3/4 5-5 03/25/10B3/4 5-6 03/25/10B3/4 5-7 03/25/10B3/4 5-8 through B3/4 5-11 03/25/10B3/4 5-12 through 83/4 5-20 03/24/12B3/4 6-1 through B3/4 6-2 04/13/09B3/4 6-3 05/27/10B3/4 6-4 through B3/4 6-6 04/13/09B3/4 6-7 through B3/4 6-12 04/13/0983/4 6-13 through 83/4 6-18 04/13/09B3/4 6-19 through 83/4 6-20 04/13/09B3/4 6-21 04/13/0983/4 7-1 04/30/02B3/4 7-2 08/14/0183/4 7-2a 11/17/95EPL-20March 24, 2012 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaqe RevisionB3/4 7-2b 04/11/05B3/4 7-3 06/12/09B3/4 7-3a 06/08/98B3/4 7-4 09/28/07B3/4 7-4a 10/05/12B3/4 7-4b 10/05/12B3/4 7-4c thru B3/4 7-4m 10/28/08B3/4 7-5 08/18/05B3/4 7-6 (DELETED) 08/28/98B3/4 7-7 12/28/05B3/4 7-8 08/12/97B3/4 7-9 12/19/00B3/4 7-10 12/19/00B3/4 7-11 12/19/00B3/4 7-12 12/19/00B3/4 7-13 12/19/00B3/4 7-14 12/19/00B3/4 7-15 12/19/00B3/4 7-16 01/31/05B3/4 7-17 02/27/02B3/4 7-18 02/27/02B3/4 8-1 12/21/12B3/4 8-2 12/21/12B3/4 8-3 12/21/12B3/4 8-4 12/21/12B3/4 8-5 12/21/12*Original pages are not dated (2/29/80).

EPL-21December 21, 2012 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaqe RevisionB3/4 8-6 12/21/12B3/4 8-7 12/21/12B3/4 8-8 12/21/12B3/4 8-9 12/21/12B3/4 9-1 09/20/04B3/4 9-2 12/28/05B3/4 9-3 04/19/04B3/4 10-1 09/20/04B3/4 11-1 12/09/93B3/4 11-2 11/16/9083/4 12-1 11/16/905-1 08/02/065-2 08/02/065-3 08/02/065-4 08/02/065-5 12/19/005-5a 12/19/005-5b 08/02/065-5c 12/19/005-5d 12/19/005-5e 12/19/00EPL-22December 21, 2012 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGAppendix CAppendix C Cover Sheet 09/06/12Table of Contents 09/06/12C-1 09/06/12C-2 09/06/12EPL-25September 6, 2012 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Lower Power License andTechnical Specifications issuedAmendment 1 issued by NRCAmendment 2 issued by NRCAmendment 3 issued by NRCAmendment 4 issued by NRCFull Power License andTechnical Specifications issuedNRC Order issued* Amendment 1 issued by NRCAmendment 2 issued by NRCAmendment 3 issued by NRCAmendment 4 issued by NRCAmendment 5 issued by NRCAmendment 6 issued by NRCEPL RevisedAmendment 7 issued by NRCAmendment 8 issued by NRCAmendment 9 issued by NRCAmendment 10 issued by NRCAmendment 11 issued by NRCAmendment 12 issued by NRCAmendment 13 issued by NRCAmendment 14 issued by NRCAmendment 15 issued by NRCAmendment 16 issued by NRCAmendment 17 issued by NRCAmendment 18 issued by NRCAmendment 19 issued by NRCAmendment 20 issued by NRCAmendment 21 issued by NRCAmendment 22 issued by NRCAmendment 23 issued by NRCAmendment 24 issued by NRCAmendment 25 issued by NRCAmendment 26 issued by NRCAmendment 27 issued by NRCAmendment 28 issued by NRCAmendment 29 issued by NRC*Amendments to Full Power License02/29/80 (Original) 04/22/80 (R1)07/01/80 (R2)07/01/80 (R2)07/10/80 (R2)09/17/80 (R3)11/06/80 (R4)12/22/80 (R5)02/09/81 (R6)02/13/81 (R6)03/06/81 (R7)04/15/81 (R8)04/27/81 (R9)06/01/81 (R10)06/26/81 (R11)07/15/81 (R12)09/08/81 (R13)12/31/81 (R14)01/29/82 (R15)03/25/82 (R16)05/04/82 (R17)06/18/82 (R18)08/03/82 (R19)10/21/82 (R20)12/23/82 (R21)12/23/82 (R22)12/23/82 (R23)12/23/82 (R24)12/23/82 (R25)12/27/82 (R26)12/27/82 (R27)12/29/82 (R28)12/29/82 (R29)03/14/83 (R30)03/16/83 (R31)05/03/83 (R32)05/05/83 (R33)EPL-26September 6, 2012 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Amendment 30 issued by NRCAmendment 31 issued by NRCAmendment 32 issued by NRCAmendment 33 issued by NRCAmendment 34 issued by NRCAmendment 35 issued by NRCAmendment 36 issued by NRCAmendment 37 issued by NRCAmendment 38 issued by NRCAmendment 39 issued by NRCAmendment 40 issued by NRCAmendment 41 issued by NRCAmendment 42 issued by NRCAmendment 43 issued by NRCEPL RevisedAmendment 44 issued by NRCAmendment 45 issued by NRCAmendment 46 issued by NRCAmendment 47 issued by NRCAmendment 48 issued by NRCAmendment 49 issued by NRCAmendment 50 issued by NRCAmendment 51 issued by NRCSpecial Amendment Authorized by NRC**Amendment 52 issued by NRCAmendment 53 issued by NRCAmendment 54 issued by NRCAmendment 55 issued by NRCAmendment 56 issued by NRCBases Revision issued by NRCAmendment 57 issued by NRCAmendment 58 issued by NRCAmendment 59 issued by NRCAmendment 60 issued by NRCAmendment 61 issued by NRCAmendment 62 issued by NRCAmendment 63 issued by NRCAmendment 64 issued by NRCAmendment 65 issued by NRCAmendment 66 issued by NRCAdditional Exemptions issued by NRCAmendment 67 issued by NRC05/05/83 (R34)09/30/83 (R35)11/10/83 (R36)03/29/84 (R37)04/12/84 (R38)04/24/84 (R39)11/23/84 (R40)01/24/85 (R41)06/11/85 (R42)06/20/85 (R43)06/25/85 (R44)09/03/85 (R45)01/14/86 (R46)01/29/86 (R47)07/17/8607/28/86 (R48)09/15/86 (R49)09/16/86 (R50)09/17/86 (R51)10/02/86 (R52)10/28/86 (R53)12/01/86 (R54)12/02/86 (R55)01/05/87 (SR)02/03/87 (R56)02/12/87 (R57)03/16/87 (R58)05/12/87 (R59)07/20/87 (R60)08/18/87 (BR)09/09/87 (R61)09/10/87 (R62)09/18/87 (R63)10/19/87 (R64)10/22/87 (R65)10/30/87 (R66)12/31/87 (R67)01/07/88 (R68)01/11/88 (R69)01/25/88 (R70)01/15/88 (AE)02/11/88 (R71)Special Revision authorized by 10 CFR Parts 50 and 51 Final Rule as noted in theFederal Register on November 6, 1986 and effective January 5, 1987.EPL-27September 6, 2012 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Amendment 68 issued by NRCAmendment 69 issued by NRCAmendment 70 issued by NRCAmendment 71 issued by NRCAmendment 72 issued by NRCAmendment 73 issued by NRCAmendment 74 issued by NRCAmendment 75 issued by NRCAmendment 76 issued by NRCAmendment 77 issued by NRCAmendment 78 issued by NRCAmendment 79 issued by NRCAmendment 80 issued by NRCAmendment 81 issued by NRCAmendment 82 issued by NRCAmendment 83 issued by NRCAmendment 84 issued by NRCAmendment 85 issued by NRCAmendment 86 issued by NRCAmendment 87 issued by NRCAmendment 88 issued by NRCAmendment 89 issued by NRCAmendment 90 issued by NRCAmendment 91 issued by NRCAmendment 92 issued by NRCAmendment 93 issued by NRCAmendment 94 issued by NRCAmendment 95 issued by NRCAmendment 96 issued by NRCAmendment 97 issued by NRCAmendment 98 issued by NRCAmendment 99 issued by NRCAmendment 100 issued by NRCAmendment 101 issued by NRCAmendment 102 issued by NRCAmendment 103 issued by NRCAmendment 104 issued by NRCAmendment 105 issued by NRCAmendment 106 issued by NRCAmendment 107 issued by NRCAmendment 108 issued by NRCAmendment 109 issued by NRCAmendment 110 issued by NRCAmendment 111 issued by NRCAmendment 112 issued by NRC02/17/88 (R72)04/04/88 (R73)05/16/88 (R74)05/18/88 (R75)05/23/88 (R76)06/24/88 (R77)06/30/88 (R78)07/06/88 (R79)07/12/88 (R80)08/05/88 (R81)08/15/88 (R82)08/15/88 (R83)08/16/88 (R84)09/01/88 (R85)09/09/88 (R86)09/21/88 (R87)09/22/88 (R88)09/22/88 (R89)10/14/88 (R90)10/14/88 (R91)10/14/88 (R92)10/14/88 (R93)10/14/88 (R94)12/05/88 (R95)12/29/88 (R96)12/29/88 (R97)12/30/88 (R98)01/23/89 (R99)01/22/89 (R100)01/22/89 (R101)01/30/89 (R102)01/30/89 (R103)01/31/89 (R104)02/28/89 (R105)03/02/89 (R106)03/06/89 (R107)03/09/89 (R108)03/09/89 (R109)03/13/89 (R110)03/15/89 (Rl11)03/28/89 (RI 12)04/03/89 (R113)04/03/89 (Ri 14)04/03/89 (Rl15)04/28/89 (Ri 16)September 6, 2012EPL-28 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Amendment 113 issued by NRCAmendment 114 issued by NRCAmendment 115 issued by NRCAmendment 116 issued by NRCAmendment 117 issued by NRCAmendment 118 issued by NRCAmendment 119 issued by NRCAmendment 120 issued by NRCAmendment 121 issued by NRCAmendment 122 issued by NRCAmendment 123 issued by NRCAmendment 124 issued by NRCAmendment 125 issued by NRCAmendment 126 issued by NRCAmendment 127 issued by NRCAmendment 128 issued by NRCAmendment 129 issued by NRCAmendment 130 issued by NRCAmendment 131 issued by NRCAmendment 132 issued by NRCAmendment 133 issued by NRCBases RevisionAmendment 134 issued by NRCAmendment 135 issued by NRCAmendment 136 issued by NRCAmendment 137 issued by NRCBases RevisionAmendment 138 issued by NRCAmendment 139 issued by NRCAmendment 140 issued by NRCAmendment 141 issued by NRCAmendment 142 issued by NRCAmendment 143 issued by NRCAmendment 144 issued by NRCAmendment 145 issued by NRCAmendment 146 issued by NRCAmendment 147 issued by NRCAmendment 148 issued by NRCAmendment 149 issued by NRCAmendment 150 issued by NRCAmendment 151 issued by NRCAmendment 152 issued by NRCAmendment 153 issued by NRCAmendment 154 issued by NRCAmendment 155 issued by NRCAmendment 156 issued by NRCAmendment 157 issued by NRCAmendment 158 issued by NRCAmendment 159 issued by NRCAmendment 160 issued by NRC05/04/89 (R117)05/05/89 (R118)05/11/89 (R119)06/01/89 (R 120)06/19/89 (R121)06/23/89 (R122)07/05/89 (R123)07/05/89 (R124)07/31/89 (R 125)08/03/89 (RI126)08/11/89 (R127)08/11/89 (R128)08/14/89 (R129)09/19/89 (R130)09/29/89 (R131)11/01/89 (R132)11/28/89 (R133)02/16/90 (R134)03/02/90 (R135)03/19/90 (R136)03/22/90 (R137)03/23/90 (BR-1)04/02/90 (R138)04/27/90 (R139)04/27/90 (R140)04/27/90 (R141)05/01/90 (BR-2)05/08/90 (R142)05/09/90 (R143)05/11/90 (R144)05/16/90 (R145)07/27/90 (R146)07/31/90 (R147)08/31/90 (R148)09/20/90 (R149)09/21/90 (R150)11/02/90 (R151)11/16/90 (R152)12/07/90 (R153)03/18/91 (R154)07/24/91 (R155)08/22/91 (R156)09/10/91 (R157)10/18/91 (R158)10/23/91 (R159)12/16/91 (R160)03/30/92 (R161)03/31/92 (R162)07/09/92 (R163)07/24/92 (R164)September 6, 2012EPL-29 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Amendment 161 issued by NRCAmendment 162 issued by NRCAmendment 163 issued by NRCAmendment 164 issued by NRCBases RevisionAmendment 165 issued by NRCBases RevisionAmendment 166 issued by NRCAmendment 167 issued by NRCAmendment 168 issued by NRCAmendment 169 issued by NRCAmendment 170 issued by NRCAmendment 171 issued by NRCAmendment 172 issued by NRCAmendment 173 issued by NRCAmendment 174 issued by NRCAmendment 175 issued by NRCAmendment 176 issued by NRCAmendment 177 issued by NRCAmendment 178 issued by NRCAmendment 179 issued by NRCAmendment 180 issued by NRCAmendment 181 issued by NRCAmendment 182 issued by NRCAmendment 183 issued by NRCAmendment 184 issued by NRCAmendment 185 issued by NRCAmendment 186 issued by NRCAmendment 187 issued by NRCAmendment 188 issued by NRCAmendment 189 issued by NRCAmendment 190 issued by NRCAmendment 191 issued by NRCAmendment 192 issued by NRCAmendment 193 issued by NRCAmendment 194 issued by NRCAmendment 195 issued by NRCBases RevisionAmendment 196 issued by NRCAmendment 197 issued by NRCAmendment 198 issued by NRCAmendment 199 issued by NRCAmendment 200 issued by NRCAmendment 201 issued by NRCAmendment 202 issued by NRCAmendment 203 issued by NRCAmendment 204 issued by NRCAmendment 205 issued by NRCAmendment 206 issued by NRCBases Revision08/10/92 (R165)08/13/92 (R166)09/28/92 (R167)11/06/92 (R168)11/25/92 (BR-3)12/08/92 (R169)12/08/92 (BR-4)01/12/93 (R170)04/28/93 (R171)06/25/93 (R172)08/02/93 (R173)08/27/93 (R174)10/26/93 (R175)11/26/93 (R176)11/29/93 (R177)12/09/93 (R178)01/03/94 (R179)02/10/94 (R180)03/15/94 (R18 1)03/31/94 (R 182)04/18/94 (R183)04/18/94 (R184)05/23/94 (R185)05/24/94 (R186)05/27/94 (R187)07/11/94 (R188)07/26/94 (R189)09/13/94 (R190)10/17/94 (R191)10/17/94 (R192)10/20/94 (R193)11/09/94 (R194)11/22/94 (R195)12/27/94 (R196)01/03/95 (R197)01/24/95 (R198)02/09/95 (R199)03/02/95 (BR-5)04/04/95 (R200)04/28/95 (R201)05/10/95 (R202)05/30/95 (R203)05/30/95 (R204)06/01/95 (R205)06/13/95 (R206)06/13/95 (R207)06/14/95 (R208)06/29/95 (R209)08/02/95 (R210)08/11/95 (BR-6)September 6, 2012EPL-30 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Amendment 207 issued by NRCAmendment 208 issued by NRCAmendment 209 issued by NRCAmendment 210 issued by NRCAmendment 211 issued by NRCAmendment 212 issued by NRCAmendment 213 issued by NRCAmendment 214 issued by NRCBases RevisionBases RevisionAmendment 215 issued by NRCAmendment 216 issued by NRCAmendment 217 issued by NRCAmendment 218 issued by NRCBases RevisionAmendment 219 issued by NRCAmendment 220 issued by NRCAmendment 221 issued by NRCBases RevisionBases RevisionAmendment 222 issued by NRCAmendment 223 issued by NRCAmendment 224 issued by NRCAmendment 225 issued by NRCAmendment 226 issued by NRCAmendment 227 issued by NRCAmendment 228 issued by NRCAmendment 229 issued by NRCAmendment 230 issued by NRCAmendment 231 issued by NRCAmendment 232 issued by NRCAmendment 233 issued by NRCAmendment 234 issued by NRCAmendment 235 issued by NRCBases RevisionAmendment 236 issued by NRCAmendment 237 issued by NRCAmendment 238 issued by NRCAmendment 239 issued by NRCAmendment 240 issued by NRCAmendment 241 issued by NRCBases RevisionAmendment 242 issued by NRCAmendment 243 issued by NRCAmendment 244 issued by NRCAmendment 245 issued by NRCAmendment 246 issued by NRCAmendment 247 issued by NRC08/22/95 (R211)08/22/95 (R212)09/06/95 (R213)09/13/95 (R214)09/15/95 (R215)10/02/95 (R216)10/04/95 (R217)10/11/95 (R218)10/27/95 (BR-7)11/17/95 (BR-8)11/21/95 (R219)12/11/95 (R220)02/05/96 (R221)02/07/96 (R222)02/15/96 (BR-9)03/01/96 (R223)03/04/96 (R224)04/26/96 (R225)09/13/96 (BR-1 0)01/02/97 (BR-11)04/09/97 (R226)04/21/97 (R227)06/10/97 (R228)07/01/97 (R229)07/14/97 (R230)08/12/97 (R231)09/23/97 (R232)09/29/97 (R233)01/13/98 (R234)02/20/98 (R235)06/08/98 (R236)07/01/98 (R237)07/22/98 (R238)08/28/98 (R239)09/09/98 (BR-12)11/17/98 (R240)11/17/98 (R241)11/19/98 (R242)11/19/98 (R243)12/07/98 (R244)12/16/98 (R245)01/25/99 (BR-13)02/09/99 (R246)03/16/99 (R247)05/04/99 (R248)09/07/99 (R249)09/23/99 (R250)10/06/99 (R251)EPL-31September 6, 2012 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Amendment 248 issued by NRCAmendment 249 issued by NRCAmendment 250 issued by NRCAmendment 251 issued by NRCAmendment 252 issued by NRCAmendment 253 issued by NRCAmendment 254 issued by NRCAmendment 255 issued by NRCBases RevisionBases RevisionAmendment 256 issued by NRCAmendment 257 issued by NRCAmendment 258 issued by NRCAmendment 259 issued by NRCAmendment 260 issued by NRCAmendment 261 issued by NRCAmendment 262 issued by NRCAmendment 263 issued by NRCAmendment 264 issued by NRCAmendment 265 issued by NRCAmendment 266 issued by NRCAmendment 267 issued by NRCAmendment 268 issued by NRCBases RevisionBases RevisionAmendment 269 issued by NRCAmendment 270 issued by NRCBases RevisionBases RevisionAmendment 271 issued by NRCAmendment 272 issued by NRCBases RevisionAmendment 273 issued by NRCAmendment 274 issued by NRCAmendment 275 issued by NRCBases RevisionAmendment 276 issued by NRCAmendment 277 issued by NRCAmendment 279 issued by NRCAmendment 280 issued by NRCAmendment 281 issued by NRCAmendment 282 issued by NRCAmendment 283 issued by NRCAmendment 284 issued by NRCAmendment 285 issued by NRCBases RevisionAmendment 286 issued by NRCAmendment 287 issued by NRCBases Revision10/12/99 (R252)02/11/00 (R253)02/22/00 (R254)02/29/00 (R255)03/08/00 (R256)03/29/00 (R257)03/29/00 (R258)04/14/00 (R259)05/25/00 (BR-14)05/25/00 (BR-15)05/31/00 (R260)07/18/00 (R261)07/31/00 (R262)08/04/00 (R263)08/28/00 (R264)10/02/00 (R265)10/06/00 (R266)11/02/00 (R267)12/18/00 (R268)12/19/00 (R269)02/16/01 (R270)03/22/01 (R271)05/09/01 (R272)06/28/01 (BR-16)07/11/01 (BR-17)07/12/01 (R273)07/18/01 (R274)07/20/01 (BR-18)08/14/01 (BR-19)10/24/01 (R275)01/14/02 (R276)02/14/02 (BR-20)02/27/02 (R277)03/08/02 (R278)04/30/02 (R279)05/17/02 (BR-21)05/24/02 (R280)09/05/02 (R281)09/30/02 (R283)02/05/03 (R284)02/11/03 (R285)03/04/03 (R286)04/24/03 (R287)04/25/03 (R288)05/22/03 (R289)05/22/03 (BR-22)05/27/03 (R290)05/29/03 (R291)06/26/03 (BR-23)September 6, 2012EPL-32 SEQUOYAH NUCLEAR PLANT UNIT ITECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Amendment 288 issued by NRCBases RevisionBases RevisionAmendment 290 issued by NRCAmendment 291 issued by NRCAmendment 292 issued by NRCAmendment 293 issued by NRCAmendment 294 issued by NRCAmendment 295 issued by NRCAmendment 296 issued by NRCLicense Condition Issued by NRCAmendment 297 issued by NRCBases RevisionAmendment 298 issued by NRCBases RevisionBases RevisionAmendment 299 issued by NRCAmendment 300 issued by NRCAmendment 301 issued by NRCAmendment 302 issued by NRCAmendment 303 issued by NRCAmendment 304 issued by NRCAmendment 305 issued by NRCAmendment 306 issued by NRCAmendment 307 issued by NRCBases RevisionAmendment 308 issued by NRCAmendment 309 issued by NRCAmendment 310 issued by NRCAmendment 311 issued by NRCAmendment 312 issued by NRCAmendment 313 issued by NRCAmendment 314 issued by NRCAmendment 315 issued by NRCLicense Condition Issued by NRCBases RevisionLicense Condition Issued by NRCAmendment 316 issued by NRCAmendment 317 issued by NRCBases RevisionAmendment 318 issued by NRCBases RevisionAmendment 319 issued by NRCBases RevisionAmendment 320 issued by NRCAmendment 321 issued by NRCAmendment 322 issued by NRCAmendment 323 issued by NRCAmendment 324 issued by NRCBases RevisionAmendment 325 issued by NRCAmendment 326 issued by NRCAmendment 327 issued by NRC10/28/03 (R292)12/22/03 (BR-24)04/19/04 (BR-25)04/21/04 (R294)06/18/04 (R295)05/21/04 (R296)07/08/04 (R297)09/15/04 (R298)09/20/04 (R299)09/20/04 (R300)10/28/0411/09/04 (R301)10/13/04 (BR-26)01/31/05 (R302)02/25/05 (BR-27)03/04/05 (BR-28)03/09/05 (R303)04/05/05 (R304)04/11/05 (R305)05/24/05 (R306)08/18/05 (R307)09/02/05 (R308)12/28/05 (R309)02/23/06 (R310)04/06/06 (R31 1)05/18/06 (BR-29)06/16/06 (R312)08/02/06 (R313)09/13/06 (R314)09/14/06 (R315)10/04/06 (R316)11/07/06 (R317)11/16/06 (R318)12/11/06 (R319)02/08/0703/07/07 (BR-30)08/09/07 (B.5.b)09/20/07 (R320)09/28/07 (R321)12/12/07 (BR-31)04/02/08 (R322)08/29/08 (BR-32)08/29/08 (R323)08/28/08 (BR-33)09/24/0810/28/0812/04/0804/13/0906/12/0906/12/09 (BR-34)08/14/0901/28/1002/02/10September 6, 2012EPL-33 SEQUOYAH NUCLEAR PLANT UNIT 1TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Revisions Bases RevisionBases RevisionAmendment 328 issued by NRCBases RevisionAmendment 330 issued by NRCBases RevisionAmendment 332 issued by NRCBases RevisionBases Revision03/25/10 (BR-35)05/27/10 (BR-36)12/21/1003/24/12 (BR-38)09/06/1210/05/12 (BR-39)10/31/1212/21/12 (BR-41)03/05/13 (BR-42)EPL-34March 5, 2013 INDEXBASESSECTION PAGE3/4.7.4 ESSENTIAL RAW COOLING WATER SYSTEM ...........................................................

B 3/4 7-3a3/4.7.5 U LTIM ATE H EAT SIN K (U HS) .........................................................................................

B 3/4 7-43/4.7.6 FLO O D P R O T EC T IO N .....................................................................................................

B 3/4 7-43/4.7.7 CONTROL ROOM EMERGENCY VENTILATION SYSTEM ...........................................

B 3/4 7-43/4.7.8 AUXILIARY BUILDING GAS TREATMENT SYSTEM .....................................................

B 3/4 7-53/4.7.9 S N U B B E R S (D eleted) ....................................................................................................

B 3/4 7-53/4.7.10 SEALED SOURCE CONTAMINATION (Deleted)

...........................................................

B 3/4 7-73/4.7.11 FIRE SUPPRESSION SYSTEMS (Deleted)

...................................................................

B 3/4 7-73/4.7.12 FIRE BARRIER PENETRATIONS (Deleted)

...................................................................

B 3/4 7-83/4.7.13 SPENT FUEL POOL MINIMUM BORON CONCENTRATION

.........................................

B 3/4 7-93/4.7.14 CASK PIT POOL MINIMUM BORON CONCENTRATION

............................................

B 3/4 7-133/4.7.15 CONTROL ROOM AIR-CONDITIONING SYSTEM (CRACS) .......................................

B 3/4 7-163/4.8 ELECTRICAL POWER SYSTEMS3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWERD IST R IBU T IO N SY ST EM S ..............................................................................................

B 3/4 8-13/4.8.3 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES (Deleted)

...................................

B 3/4 8-93/4.9 REFUELING OPERATIONS 3/4.9.1 BO RO N C O NC ENTRATIO N ............................................................................................

B 3/4 9-13/4 .9.2 IN ST R U M E N TA T IO N .......................................................................................................

B 3/4 9-13/4 .9 .3 D E C A Y T IM E ....................................................................................................................

B 3/4 9-13/4.9.4 CONTAINMENT BUILDING PENETRATIONS

................................................................

B 3/4 9-13/4.9.5 COMMUNICATIONS (Deleted)

.......................................................................................

B 3/4 9-23/4.9.6 MANIPULATOR CRANE (Deleted)

.................................................................................

B 3/4 9-23/4.9.7 CRANE TRAVEL -SPENT FUEL PIT AREA (Deleted)

..................................................

B 3/4 9-23/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION

......................................

B 3/4 9-23/4.9.9 CONTAINMENT VENTILATION SYSTEM .......................................................................

B 3/4 9-3December 21, 2012SEQUOYAH

-UNIT 1 XIV Amendment No. 157, 204, 227, 235, 265,273, 305, 332 INSTRUMENTATION BASESACCIDENT MONITORING INSTRUMENTATION (Continued)

Provide information to the operators that will enable them to determine the likelihood of a gross breach ofthe barriers to radioactivity release and to determine if a gross breach of a barrier has occurred.

For Sequoyah, the redundant channel capability for Auxiliary Feedwater (AFW) flow consists of asingle AFW flow channel for each Steam Generator with the second channel consisting of three AFW valveposition indicators (two level control valves for the motor driven AFW flowpath and one level control valve forthe turbine driven AFW flowpath) for each steam generator.

March 5, 2013SEQUOYAH

-UNIT 1 B3/4 3-3a Amendment No. 149, 159 RCS Pressure and Temperature (PIT) LimitsB 3/4.4.9TABLE B 3/4.4-1SEQUOYAH-UNIT 1 REACTOR VESSEL TOUGHNESS DATAMATERIAL Cu Ni NDT MINIMUM RTNDT AVERAGE UPPERCOMPONENT HEAT NO. GRADE (%) (%) (OF) 50 ft-lb/35 mil temp. (OF) SHELF ENERGYTEMP.(0F) (ft-lb)PMWD1 NMWD2 PMWD1 NMWD2Clos Hd. Dome 52841-1 A533B,C1.1

-40 +14 +34 -26 104a -Clos Hd. Ring (D75600)

A508,C1.2

+ 5 +36 +56* +5 125a -Hd Flange 4842 A508,C1.2

---40 4* -40 131a -Vessel Flange 4866 A508,C1.2

---49 27 -49 158a -Inlet Nozzle 4846 A508,CI.2

--58 +25 +45 -15 94.5a -Inlet Nozzle 4949 A508,C1 .2 --40 +39 +59* -1 93a -Inlet Nozzle 4863 A508,C1.2

-22 +16 +36* -22 118a -Inlet Nozzle 4865 A508,C1.2

-67 +9 +29* -31 94a -Outlet Nozzle 4845 A508,C1.2

-49 +21 +41* -19 948 -Outlet Nozzle 4850 A508,C1.2

-58 +30 +50* -10 79.5a -Outlet Nozzle 4862 A508,C1.2

-58 +16 +36* -24 103a -Outlet Nozzle 4864 A508,C1.2

-49 0 +20 -40 126a -Upper Shell 4841 A508,C1.2

-40 +43 +83 +23 83a 113'Inter Shell 4829 A508,C1.2 0.15 0.86 -4 +10 +100 +40 116 73b'cLower Shell 4836 A508,C1.2 0.13 0.76 +5 +28 +133 +73 109 70bTrans. Ring 4879 A508,CI.2

--+5 +27 +47* + 5 98aBot. Hd. Rim 52703/2-1 A533B,C1.1

---31 +23 +43* -17 104aBot. Hd. Rim 52703/2-2 A533B,C1.1

---13 +36 +56* -4 638Bot. Hd. Rim 52704/2 A533B,C1.1

---49 4* -49 114aBot. Hd. Rim 52703/2-2 A533B,C1.1

---31 +43 +63* +3 86aBot. Hd. Rim 52704/2 A533B,C1.1

---58 -13 +4 -53 120aBot. Hd. 52704/11 A533B,C1.1

---58 27* -58 139aWeld -Weld 0.33 0.17 -4 -40 116bHAZ Weld ---22 +41 -19 86b1-Paralled to Major Working Direction 2-Normal to Major Working Direction a-%Shear Not reportedb-Minimum upper shelf energiesc-Minimum upper shelf energy decreased to 51 at a testtemperature of 3000F. This anomalywill be reevaluted when the results of Generic task A-i 1are available.

Estimate based on USAEC Regulatory Standard Review Plan, Section 5.3.2MTEBNovember 9, 2004Amendment No. 158, 294, 297SEQUOYAH UNIT 1B 3/4 4-12 ECCS -ShutdownB 3/4.5.3B 3/4.5 EMERGENCY CORE COOLING SYSTEM (ECCS)B 3/4.5.3 ECCS -ShutdownBASESBACKGROUND The Background section for Bases 3.5.2, "ECCS -Operating,"

isapplicable to these Bases, with the following modifications.

In MODE 4,the required ECCS train consists of two separate subsystems:

centrifugal charging (high head) and residual heat removal (RHR) (lowhead). For the RHR subsystem during the injection phase, water is takenfrom the refueling storage tank (RWST) and injected in the ReactorCoolant System (RCS) through at least two cold legs.The ECCS flow paths consist of piping, valves, heat exchangers, andpumps such that water from the refueling water storage tank (RWST) canbe injected into the Reactor Coolant System (RCS) following theaccidents described in Bases 3.5.2.APPLICABLE SAFETYANALYSESThe Applicable Safety Analyses section of Bases 3.5.2 also applies tothis Bases section.Due to the stable conditions associated with operation in MODE 4 and thereduced probability of occurrence of a Design Basis Accident (DBA), theECCS operational requirements are reduced.

It is understood in thesereductions that certain automatic safety injection (SI) actuation is notavailable.

In this MODE, sufficient time exists for manual .actuation of therequired ECCS to mitigate the consequences of a DBA.Only one train of ECCS is required for MODE 4. This requirement dictates that single failures are not considered during this MODE ofoperation.

One train of ECCS during the injection phase provides sufficient flow forcore cooling, by the centrifugal charging subsystem supplying each of thefour cold legs and the RHR subsystem supplying at least two cold legs, tomeet the analysis requirements for a credible Mode 4 Loss of CoolantAccident (LOCA.)The ECCS trains satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCOIn MODE 4, one of the two independent (and redundant)

ECCS trains isrequired to be OPERABLE to ensure that sufficient ECCS flow isavailable to the core following a DBA.SEQUOYAH

-UNIT 1March 24, 2012BR35, BR38B 3/4 5-12 ECCS -ShutdownB 3/4.5.3BASESLCO (continued)

In MODE 4, an ECCS train consists of a centrifugal charging subsystem and an RHR subsystem.

Each train includes the piping, instruments, andcontrols to ensure an OPERABLE flow path capable of taking suctionfrom the RWST and transferring suction to the containment sumpDuring an event requiring ECCS actuation, a flow path is required toprovide an abundant supply of water from the RWST to the RCS via theECCS pumps and their respective supply headers to the coldleg injection nozzles.

In the long term, this flow path may be switched totake its supply from the containment sump and to deliver its flow to theRCS hot and cold legs.Either RHR cold leg injection valve FCV-63-93 or FCV-63-94 may beclosed when in Mode 4, for testing of the primary/secondary check valvesin the injection lines. Closing one of the two cold leg injection flow pathsdoes not make ECCS RHR subsystem inoperable.

This LCO is modified by a Note that allows an RHR train to be considered OPERABLE during alignment and operation for decay heat removal, ifcapable of being manually realigned (remote or local) to the ECCS modeof operation and not otherwise inoperable.

The manual actionsnecessary to realign the RHR subsystem may include actions to cool theRHR system piping due to the potential for steam voiding in piping or forinadequate NPSH available at the RHR pumps. This allows operation inthe RHR mode during MODE 4.APPLICABILITY In MODES 1, 2, and 3, the OPERABILITY requirements for ECCS arecovered by LCO 3.5.2.In MODE 4 with RCS temperature below 350°F, one OPERABLE ECCStrain is acceptable without single failure consideration, on the basis of thestable reactivity of the reactor and the limited core cooling requirements.

In MODES 5 and 6, plant conditions are such that the probability of anevent requiring ECCS injection is extremely low. Core coolingrequirements in MODE 5 are addressed by LCO 3.4.1.4, "ReactorCoolant System Cold Shutdown."

MODE 6 core cooling requirements areaddressed by LCO 3.9.8.1 "Residual Heat Removal and CoolantCirculation

-All Water Levels,"

and LCO 3.9.8.2 "Residual Heat Removaland Coolant Circulation

-Low Water Level."March 24, 2012SEQUOYAH

-UNIT 1 B 3/4 5-13 BR35, BR36, BR38 ECCS -ShutdownB 3/4.5.3BASESACTIONS A Note prohibits the application of LCO 3.0.4b to an inoperable ECCShigh head subsystem when entering MODE 4. There is an increased riskassociated with entering MODE 4 from MODE 5 with an inoperable ECCShigh head subsystem and the provisions of LCO 3.0.4b, which allow entryinto a MODE or other specified condition in the Applicability with the LCOnot met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

A second Note allows the required ECCS RHR subsystem to beinoperable because of surveillance testing of RCS pressure isolation valve leakage (FCV-74-1 and FCV-74-2).

This allows testing while RCSpressure is high enough to obtain valid leakage data and following valveclosure for RHR decay heat removal path. The condition requiring alternate heat removal methods ensures that the RCS heatup rate can becontrolled to prevent MODE 3 entry and thereby ensure that the reducedECCS operational requirements are maintained.

The condition requiring manual realignment capability, FCV-74-1 and FCV-74-2 can be openedfrom the main control room ensures that in the unlikely event of a DBAduring the one hour of surveillance

testing, the RHR subsystem can beplaced in ECCS recirculation mode when required to mitigate the event.Action a.With no ECCS RHR subsystem

OPERABLE, the plant is not prepared torespond to a loss of coolant accident or to continue a cooldown using theRHR pumps and heat exchangers.

The action time of immediately toinitiate actions that would restore at least one ECCS RHR subsystem toOPERABLE status ensures that prompt action is taken to restore therequired cooling capacity.

Normally, in MODE 4, reactor decay heat isremoved from the RCS by an RHR loop. If no RHR loop is OPERABLEfor this function, reactor decay heat must be removed by some alternate method, such as use of the steam generators.

The alternate means ofheat removal must continue until the inoperable RHR loop components can be restored to operation so that decay heat removal is continuous.

With both RHR pumps and heat exchangers inoperable, it would beunwise to require the plant to go to MODE 5, where the only available heat removal system is the RHR. Therefore, the appropriate action is toinitiate measures to restore one ECCS RHR subsystem and to continuethe actions until the subsystem is restored to OPERABLE status.March 24, 2012SEQUOYAH

-UNIT 1 B 3/4 5-14 BR35 BASESACTIONS (continued)

Action b.With no ECCS high head subsystem

OPERABLE, due to the inoperability of the centrifugal charging pump or flow path from the RWST, the plant isnot prepared to provide high pressure response to Design Basis Eventsrequiring SI. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months action time to restore at least one ECCS highhead subsystem to OPERABLE status ensures that prompt action istaken to provide the required cooling capacity or to initiate actions toplace the plant in MODE 5, where an ECCS train is not required.

When Action b cannot be completed within the required action time,within one hour, a controlled shutdown should be initiated.

Twenty fourhours is a reasonable time, based on operating experience, to reachMODE 5 in an orderly manner and without challenging plant systems oroperators.

SURVEILLANCE SR 4.5.3REQUIREMENTS The applicable Surveillance descriptions from Bases 3.5.2 apply.REFERENCES

1. The applicable references from Bases 3.5.2 apply.2. NRC Safety Evaluation Report, NUREG-001 1, Section 1.1,"Introduction,"

regarding Amendment 49 dated January 6, 1978.March 24, 2012BR35, BR38SEQUOYAH

-UNIT 1B 3/4 5-15 EMERGENCY CORE COOLING SYSTEMSBASES3/4.5.4 BORON INJECTION SYSTEMThis specification was deleted.3/4.5.5 REFUELING WATER STORAGE TANKThe OPERABILITY of the RWST as part of the ECCS ensures that a sufficient supply ofborated water is available for injection by the ECCS in the event of a LOCA. The limits onRWST minimum volume and boron concentration ensure that 1) sufficient water is available within containment to permit recirculation cooling flow to the core, and 2) the reactor will remainsubcritical in the cold condition following mixing of the RWST and the RCS water volumes withall control rods inserted except for the most reactive control assembly.

These assumptions areconsistent with the LOCA analyses.

Additionally, the OPERABILITY of the RWST as part of the ECCS ensures that sufficient negative reactivity is injected into the core to counteract any positive increase in reactivity caused by RCS cooldown.

The contained water volume limit includes an allowance for water not usable because oftank discharge line location or other physical characteristics.

The limits on contained water volume and boron concentration of the RWST also ensurea pH value of between 7.5 and 9.5 for the solution recirculated within containment after a LOCA.This pH band minimizes the evolution of iodine and minimizes the effect of chloride and causticstress corrosion on mechanical systems and components.

March 24, 2012SEQUOYAH

-UNIT 1 B 3/4 5-16 Amendment No. 140, 301 EMERGENCY CORE COOLING SYSTEMBASES3/4.5.6 SEAL INJECTION FLOWBACKGROUND The function of the seal injection throttle valves during an accident issimilar to the function of the ECCS throttle valves in that each restricts flow from the centrifugal charging pump header to the Reactor CoolantSystem (RCS).The restriction on reactor coolant pump (RCP) seal injection flow limitsthe amount of ECCS flow that would be diverted from the injection pathfollowing an accident.

This limit is based on safety analysis assumptions that are required because RCP seal injection flow is not isolated duringsafety injection.

APPLICABLE All ECCS subsystems are taken credit for in the large break loss ofSAFETY ANALYSES coolant accident (LOCA) at full power (Ref. 1). The LOCA analysisestablishes the minimum flow for the ECCS pumps. The centrifugal charging pumps are also credited in the small break LOCA analysis.

Thisanalysis establishes the flow and discharge head at the design point forthe centrifugal charging pumps. The steam generator tube rupture andmain steam line break event analyses also credit the centrifugal chargingpumps, but are not limiting in their design. Reference to these analysesis made in assessing changes to the Seal Injection System for evaluation of their effects in relation to the acceptance limits in these analyses.

This LCO ensures that seal injection flow will be sufficient for RCP sealintegrity but limited so that the ECCS trains will be capable of delivering sufficient water to match boiloff rates soon enough to minimizeuncovering of the core following a large LOCA. It also ensures that thecentrifugal charging pumps will deliver sufficient water for a small LOCAand sufficient boron to maintain the core subcritical.

For smaller LOCAs,the charging pumps alone deliver sufficient fluid to overcome the loss andmaintain RCS inventory.

Seal injection flow satisfies Criterion 2 of theNRC Policy Statement.

LCOThe intent of the LCO limit on seal injection flow is to make sure that flowthrough the RCP seal water injection line is low enough to ensure thatsufficient centrifugal charging pump injection flow is directed to the RCSvia the injection points (Ref. 2).March 24, 2012Amendment No. 259SEQUOYAH

-UNIT 1B 3/4 5-17 EMERGENCY CORE COOLING SYSTEMBASESLCO (continued)

The LCO is not strictly a flow limit, but rather a flow limit based on a flowline resistance.

In order to establish the proper flow line resistance, apressure and flow must be known. The flow line resistance is established by adjusting the RCP seal injection needle valves to provide a total sealinjection flow in the acceptable region of Technical Specification Figure3.5.6-1.

The centrifugal charging pump discharge header pressureremains essentially constant through all the applicable MODES of thisLCO. A reduction in RCS pressure would result in more flow beingdiverted to the RCP seal injection line than at normal operating pressure.

The valve settings established at the prescribed centrifugal chargingpump discharge header pressure result in a conservative valve positionshould RCS pressure decrease.

The flow limits established by Technical Specification Figure 3.5.6-1 are consistent with the accident analysis.

The limits on seal injection flow must be met to render the ECCSOPERABLE.

If these conditions are not met, the ECCS flow will not beas assumed in the accident analyses.

APPLICABILITY In MODES 1, 2, and 3, the seal injection flow limit is dictated by ECCSflow requirements, which are specified for MODES 1, 2, 3, and 4. Theseal injection flow limit is not applicable for MODE 4 and lower, however,because high seal injection flow is less critical as a result of the lowerinitial RCS pressure and decay heat removal requirements in theseMODES. Therefore, RCP seal injection flow must be limited in MODES1, 2, and 3 to ensure adequate ECCS performance.

ACTIONWith the seal injection flow exceeding its limit, the amount of chargingflow available to the RCS may be reduced.

Under this condition, actionmust be taken to restore the flow to below its limit. The operator has 4hours from the time the flow is known to be above the limit to correctly position the manual valves and thus be in compliance with the accidentanalysis.

The completion time minimizes the potential exposure of theplant to a LOCA with insufficient injection flow and provides a reasonable time to restore seal injection flow within limits. This time is conservative with respect to the completion times of other ECCS LCOs; it is based onoperating experience and is sufficient for taking corrective actions byoperations personnel.

March 24, 2012Amendment No. 259SEQUOYAH

-UNIT 1B 3/4 5-18 EMERGENCY CORE COOLING SYSTEMBASESACTIONS(continued)

When the actions cannot be completed within the required completion time, a controlled shutdown must be initiated.

The completion time of 6hours for reaching MODE 3 from MODE 1 is a reasonable time for acontrolled

shutdown, based on operating experience and normalcooldown rates, and does not challenge plant safety systems oroperators.

Continuing the plant shutdown from MODE 3, an additional 6hours is a reasonable time, based on operating experience and normalcooldown rates, to reach MODE 4, where this LCO is no longerapplicable.

SURVEILLANCE Surveillance 4.5.6REQUIREMENTS Verification every 31 days that the manual seal injection throttle valvesare adjusted to give a flow within the limit ensures that proper manualseal injection throttle valve position, and hence, proper seal injection flow,is maintained.

The differential pressure that is above the reference minimum value is established between the charging header (PT 62-92)and the RCS, and total seal injection flow is verified to be within the limitsdetermined in accordance with the ECCS safety analysis (Ref. 3). Theseal water injection flow limits are shown in Technical Specification Figure3.5.6-1.

The frequency of 31 days is based on engineering judgment andis consistent with other ECCS valve surveillance frequencies.

Thefrequency has proven to be acceptable through operating experience.

The requirements for charging flow vary widely according to plant statusand configuration.

When charging flow is adjusted, the positions of theair-operated valves, which control charging flow, are adjusted to balancethe flows through the charging header and through the seal injection header to ensure that the seal injection flow to the RCPs is maintained between 8 and 13 gpm per pump. The reference minimum differential pressure across the seal injection needle valves ensures that regardless of the varied settings of the charging flow control valves that are requiredto support optimum charging flow, a reference test condition can beestablished to ensure that flows across the needle valves are within thesafety analysis.

The values in the safety analysis for this reference set ofconditions are calculated based on conditions during power operation andthey are correlated to the minimum ECCS flow to be maintained underthe most limiting accident conditions.

March 24, 2012SEQUOYAH

-UNIT 1 B 3/4 5-19 Amendment No. 259 EMERGENCY CORE COOLING SYSTEMBASESAs noted, the surveillance is not required to be performed until 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months afterthe RCS pressure has stabilized within a +/- 20 psig range of normal operating pressure.

The RCS pressure requirement is specified since thisconfiguration will produce the required pressure conditions necessary toassure that the manual valves are set correctly.

The exception is limited to 4hours to ensure that the surveillance is timely. Performance of thissurveillance within the 4-hour allowance is required to maintain compliance with the provisions of Specification 4.0.3.REFERENCES

1. FSAR, Chapter 6.3 "Emergency Core Cooling System" and Chapter 15.0"Accident Analysis."

2. 10 CFR 50.46.3. Westinghouse Electric Company Calculation CN-FSE-99-48 March 24, 2012Amendment No. 259SEQUOYAH

-UNIT 1B 3/4 5-20 UHSB 3/4.7.5BASESLCO (continued) head (NPSH), and without exceeding the maximum design temperature of theequipment served by the ERCW. To meet this condition, the UHS temperature should not exceed 87°F, when the ERCW System is not in the alignment tosupport large heavy load lifts associated with the Unit 2 refueling outage 18steam generator replacement

project, and the level should not fall below the 674feet mean sea level during normal unit operation.

When the ERCW System is inthe alignment to support large heavy load lifts associated with the Unit 2 refueling outage 18 steam generator replacement

project, the UHS temperature should notexceed 740F. The alignment to support these large heavy load lifts, whichmaintains the ERCW System OPERABLE in the event of large heavy load drop,is described in Appendix C, "Additional Conditions,"

of the Operating License.APPLICABILITY In MODES 1, 2, 3, and 4, the UHS is required to support theOPERABILITY of the equipment serviced by the UHS and required to beOPERABLE in these MODES.In MODE 5 or 6, the OPERABILITY requirements of the UHS aredetermined by the systems it supports.

ACTIONS The maximum allowed UHS temperature value is based on temperature limitations of the equipment that is relied upon for accident mitigation andsafe shutdown of the unit and the configuration of the ERCW System.Measurement of this temperature is in accordance with NUREG/CR-3659 methodology which includes measurement uncertainties (Ref: 5).With average water temperature of the UHS < 870F (when the ERCWSystem is not in the alignment to support large heavy load lifts) or 5 740F(when the ERCW System is in the alignment to support large heavy loadlifts), the associated design basis assumptions remain bounded for allaccidents, transients, and shutdown.

Long-term cooling capability isprovided to the Emergency Core Cooling System (ECCS) and Emergency Diesel Generator loads.If the water temperature of the UHS exceeds the limits of the LCO, theunit must be placed in a MODE in which the LCO does not apply. Toachieve this status, the unit must be placed in at least MODE 3 within 6hours and in MODE 5 within the following 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months . The allowedCompletion Times are reasonable, based on operating experience, toreach the required unit conditions from full power conditions in an orderlymanner and without challenging unit systems.SEQUOYAH

-UNIT 1B 3/4 7-4aOctober 5, 2012Amendment No. 8, 79, 247, 273,317, 330 UHSB 3/4.7.5BASESSURVEILLANCE REQUIREMENTS SR 4.7.5.1This SR verifies that the ERCW is available to cool the CCS to at least itsmaximum design temperature with the maximum accident or normaldesign heat loads for 30 days following a Design Basis Accident.

This SR also verifies that adequate long-term (30 day) cooling can bemaintained.

The specified level ensures that sufficient reservoir volumeexists at the initiation of a LBLOCA concurrent with loss of downstream dam to meet the short-term recovery.

NPSH of the ERCW pumps are notchallenged with loss of downstream dam. The 24-hour Frequency isbased on operating experience related to trending of the parameter variations during the applicable MODES.SR verifies that the average water temperature of the UHS is < 870F(when the ERCW Sysem is not in the alignment to support large heavyload lifts) and < 74°F (when the ERCW System is in the alignment tosupport large heavy load lifts) and that the UHS water level is > 674 feetmean sea level.REFERENCES

1. UFSAR, Section 9.2.5, Ultimate Heat Sink2. UFSAR, Section 6.2.1, Containment Functional Design3. UFSAR, Section 9.2.2, Essential Raw Cooling Water (ERCW)4. Regulatory Guide 1.27 RO, "Ultimate Heat Sink For Nuclear PowerPlants,"

19725. NUREG/CR-3659, "A Mathematical Model For Assessing TheUncertainties Of Instrumentation Measurements For Power AndFlow Of PWR Reactors,"

February 1985.SEQUOYAH

-UNIT 1October 5, 2012B 3/4 7-4b Amendment No. 8, 79, 247, 273, 317, 330 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMSThe OPERABILITY of the A.C. and D.C power sources and associated distribution systemsduring operation ensures that sufficient power will be available to supply the safety related equipment required for 1) the safe shutdown of the facility and 2) the mitigation and control of accident conditions within the facility.

The minimum specified independent and redundant A.C. and D.C. power sources anddistribution systems satisfy the requirements of General Design Criteria 17 of Appendix "A" to 10 CFR 50.The electrically powered AC safety loads are separated into redundant load groups such that lossof any one load group will not prevent the minimum safety functions from being performed.

Specification 3.8.1.1 requires two physically independent circuits between the offsite transmission network and theonsite Class 1 E Distribution System and four separate and independent diesel generator sets to beOPERABLE in MODES 1, 2, 3, and 4. These requirements ensure availability of the required power toshut down the reactor and maintain it in a safe shutdown condition after an abnormal operational transient or a postulated design basis accident.

Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident.

Minimum required switchyard voltages are determined by evaluation of plant accident loading and the associated voltage drops between the transmission network and theseloads. These minimum voltage values are provided to TVA's Transmission Operations for use in systemstudies to support operation of the transmission network in a manner that will maintain the necessary voltages.

Transmission Operations is required to notify SQN Operations if it is determined that thetransmission network may not be able to support accident loading or shutdown operations as required by10 CFR 50, Appendix A, GDC-17. Any offsite power circuits supplied by that transmission network thatare not able to support accident loading or shutdown operations are inoperable.

The unit station service transformers (USSTs) utilize auto load tap changers to provide therequired voltage response for accident loading.

The load tap changer associated with a USST is requiredto be functional and in "automatic" for the USST to supply power to a 6.9 kV Unit Board.The inability to supply offsite power to a 6.9 kV Shutdown Board constitutes the failure of only oneoffsite circuit, as long as offsite power is available to the other load group's Shutdown Boards. Thus, ifone or both 6.9 kV Shutdown Boards in a load group do not have an offsite circuit available, then only oneoffsite circuit would be inoperable.

If one or more Shutdown Boards in each load group, or all fourShutdown Boards, do not have an offsite circuit available, then both offsite circuits would be inoperable.

An "available" offsite circuit meets the requirements of GDC-17, and is either connected to the 6.9 kVShutdown Boards or can be connected to the 6.9 kV Shutdown Boards within a few seconds.An offsite circuit consists of all breakers, transformers,

switches, interrupting

devices, cabling,and controls required to transmit power from the offsite transmission network (beginning at theswitchyard) to one load group of Class 1 E 6.9 kV Shutdown Boards (ending at the supply side of thenormal or alternate supply circuit breaker).

Each required offsite circuit is that combination of powersources described below that are normally connected to the Class 1 E distribution system, or can beconnected to the Class 1 E distribution system through automatic transfer at the 6.9 kV Unit Boards.The following offsite power configurations meet the requirements of LCO 3.8.1.1 .a:(Note that common station service transformer (CSST) B is a spare transformer with two sets ofsecondary windings that can be used to supply a total of two Start Buses for CSST A and/or CSST C,with each supplied Start Bus on a separate CSST B secondary winding.)

December 21, 2012SEQUOYAH

-UNIT 1 B 3/4 8-1 Amendment No. 12, 137, 173, 205, 241,281,332 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

1. Two offsite circuits consisting of a AND b (no board transfers required; a loss of either circuit will notprevent the minimum safety functions from being performed):

a. From the 161 kV transmission

network, through CSST A (winding X) to Start Bus 1A to6.9 kV Shutdown Board 1 B-B (through 6.9 kV Unit Board 1C), and CSST A (winding Y) toStart Bus 2A to 6.9 kV Shutdown Board 2B-B (through 6.9 kV Unit Board 2C); ANDb. From the 161 kV transmission

network, through CSST C (winding X) to Start Bus 2B to6.9 kV Shutdown Board 2A-A (through 6.9 kV Unit Board 2B), and CSST C (winding Y) toStart Bus 1B to 6.9 kV Shutdown Board 1A-A (through 6.9 kV Unit Board IB).2. Two offsite circuits consisting of a AND b (relies on automatic transfer from alignment a.1) to b.2)(b),or a.2) to b.1)(a) on a loss of USSTs 1A and 11B, OR relies on automatic transfer from alignment a.3)to b.2)(a),

or a.4) to b.1)(b) on a loss of USSTs 2A and 2B):a. Normal power source alignments

1) From the 500 kV switchyard through USST 1A to 6.9 kV Shutdown Board 1A-A (through6.9 kV Unit Board 1B);2) From the 500 kV switchyard through USST 1 B to 6.9 kV Shutdown Board 1 B-B (through6.9 kV Unit Board lC);3) From the 161 kV switchyard through USST 2A to 6.9 kV Shutdown Board 2A-A (through6.9 kV Unit Board 2B); AND4) From the 161 kV switchyard through USST 2B to 6.9 kV Shutdown Board 2B-B (through6.9 kV Unit Board 2C).b. Alternate power source alignments

1) From the 161 kV transmission

network, through:(a) CSST A (winding X) to Start Bus 1A to 6.9 kV Shutdown Board 1 B-B (through 6.9 kVUnit Board 1C); AND(b) CSST A (winding Y) to Start Bus 2A to 6.9 kV Shutdown Board 2B-B (through 6.9 kVUnit Board 2C); OR2) From the 161 kV transmission

network, through:(a) CSST C (winding X) to Start Bus 2B to 6.9 kV Shutdown Board 2A-A (through 6.9 kVUnit Board 2B), AND(b) CSST C (winding Y) to Start Bus 1B to 6.9 kV Shutdown Board 1A-A (through 6.9 kVUnit Board 1B).December 21, 2012SEQUOYAH

-UNIT I B 3/4 8-2 Amendment No. 12, 137, 173, 205,234, 241,261,285, 301,332 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

3. Two offsite circuits consisting of a AND b (relies on automatic transfer from alignment a.1) to b.1) andb.2) on a loss of the Unit 2 USSTs; a loss of alignment a.2) or a.3) will not prevent the minimumsafety functions from being performed):

a. Normal power source alignments

1) From the 161 kV switchyard through USST 2A to 6.9 kV Shutdown Board 2A-A (through6.9 kV Unit Board 2B), and USST 2B to 6.9 kV Shutdown Board 2B-B (through 6.9 kVUnit Board 2C);2) From the 161 kV transmission

network, through CSST A (winding X) to Start Bus 1A to6.9 kV Shutdown Board 1 B-B (through 6.9 kV Unit Board 1 C); AND3) From the 161 kV transmission

network, through CSST C (winding Y) to Start Bus 1 B to6.9 kV Shutdown Board 1A-A (through 6.9 kV Unit Board 1B).b. Alternate power source alignments

1) From the 161 kV transmission

network, through CSST A (winding Y) to Start Bus 2A to6.9 kV Shutdown Board 2B-B (through 6.9 kV Unit Board 2C); AND2) From the 161 kV transmission

network, through CSST C (winding X) to Start Bus 2B to6.9 kV Shutdown Board 2A-A (through 6.9 kV Unit Board 2B).4. Two offsite circuits consisting of a AND b (relies on automatic transfer from alignment a.1) to b.1) andb.2) on a loss of the Unit 1 USSTs; a loss of alignment a.2) or a.3) will not prevent the minimumsafety functions from being performed):

a. Normal power source alignments

1) From the 500 kV switchyard through USST 1A to 6.9 kV Shutdown Board 1A-A (through6.9 kV Unit Board 1B), and USST 1B to 6.9 kV Shutdown Board 1B-B (through 6.9 kVUnit Board 1C);2) From the 161 kV transmission

network, through CSST A (winding Y) to Start Bus 2A to6.9 kV Shutdown Board 2B-B (through 6.9 kV Unit Board 2C); AND3) From the 161 kV transmission

network, through CSST C (winding X) to Start Bus 2B to6.9 kV Shutdown Board 2A-A (through 6.9 kV Unit Board 2B).b. Alternate power source alignments

1) From the 161 kV transmission

network, through CSST A (winding X) to Start Bus 1A to6.9 kV Shutdown Board 1 B-B (through 6.9 kV Unit Board 1C); AND2) From the 161 kV transmission

network, through CSST C (winding Y) to Start Bus 1 B to6.9 kV Shutdown Board 1A-A (through 6.9 kV Unit Board 1B).December 21, 2012SEQUOYAH

-UNIT 1 B 3/4 8-3 Amendment No. 12, 137, 173, 205,234, 261,285, 332 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

Other offsite power configurations are possible using different combinations of available USSTsand CSSTs, as long as the alignments are consistent with the analyzed configurations, and thealignments otherwise comply with the requirements of GDC 17.For example, to support breaker testing, offsite power to the 6.9 kV Shutdown Boards can berealigned from normal feed to alternate feed. This would result in Shutdown Boards 1A-A and 2A-A beingfed from Unit Boards 1A and 2A, respectively, and Shutdown Boards 1B-B and 2B-B being fed from UnitBoards 1 D and 2D, respectively.

The CSST being utilized as the alternate power source to one loadgroup of Shutdown Boards would also be realigned (normally CSST A available to Shutdown Boards1 B-B and 2B-B or CSST C available to Shutdown Boards 1A-A and 2A-A, would be realigned to CSST Aavailable to Shutdown Boards 1A-A and 2A-A or CSST C available to Shutdown Boards 1 B-B and 2B-B).LCO 3.8.1.1 is modified by Note @ that specifies CSST A and CSST C are required to beavailable via automatic transfer at the associated 6.9 KV Unit Boards, when USST 2A and USST 2B arebeing utilized as normal power sources to the offsite circuits.

(Note that CSST B can be substituted forCSST A or CSST C.) This offsite power alignment is consistent with Configuration 3, as stated above.Note @ remains in effect until November 30, 2013, or until the USST modifications are implemented onUnits 1 and 2, whichever occurs first. (The scheduled startup from the Unit 1 fall 2013 refueling outage isNovember 2013.) Following expiration of Note @, Configuration 3 can continue to be used.The ACTION requirements specified for the levels of degradation of the power sources providerestriction upon continued facility operation commensurate with the level of degradation.

TheOPERABILITY of the power sources are consistent with the initial condition assumptions of the accidentanalyses and are based upon maintaining at least one redundant set of onsite A.C. and D.C. powersources and associated distribution systems OPERABLE during accident conditions coincident with anassumed loss of offsite power and single failure of the other onsite A.C. source.The footnote for Action b of LCO 3.8.1.1 requires completion of a determination that theOPERABLE diesel generators are not inoperable due to common cause failure or performance ofSurveillance 4.8.1.1.2.a.4 if Action b is entered.

The intent is that all diesel generator inoperabilities mustbe investigated for common cause failures regardless of how long the diesel generator inoperability persists.

Action b of LCO 3.8.1.1 is further modified by a second note which precludes making more thanone diesel generator inoperable on a pre-planned basis for maintenance, modifications, or surveillance testing.

The intent of this footnote is to explicitly exclude the flexibility of removing a diesel generator setfrom service as a part of a pre-planned activity.

While the removal of a diesel generator set (A or B train)is consistent with the initial condition assumptions of the accident

analysis, this configuration is judged asimprudent.

The term pre-planned is to be taken in the context of those activities which are routinely scheduled and is not relative to conditions which arise as a result of emergent or unforeseen events. Asan example, this footnote is not intended to preclude the actions necessary to perform the common modetesting requirements required by Action b. As another example, this footnote is not intended to preventthe required surveillance testing of the diesel generators should one diesel generator maintenance beunexpectedly extended and a second diesel generator fall within its required testing frequency.

Thus,application of the note is intended for pre-planned activities.

December 21, 2012SEQUOYAH

-UNIT 1 B 3/4 8-4 Amendment No. 12, 137, 173, 205, 241,281,332 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

In addition, this footnote is intended to apply only to those actions taken directly on the dieselgenerator.

For those actions taken relative to common support systems (e.g. ERCW), the supportfunction must be evaluated for impact on the diesel generator.

The action to determine that the OPERABLE diesel generators are not inoperable due to commoncause failure provides an allowance to avoid unnecessary testing of OPERABLE diesel generators.

If it canbe determined that the cause of the inoperable diesel generator does not exist on the OPERABLE dieselgenerators, Surveillance Requirement 4.8.1.1.2.a.4 does not have to be performed.

If the cause ofinoperability exists on other diesel generator(s),

the other diesel generator(s) would be declared inoperable upon discovery and Action e of LCO 3.8.1.1 would be entered as applicable.

Once the common failure isrepaired, the common cause no longer exists, and the action to determine inoperability due to commoncause failure is satisfied.

If the cause of the initial inoperable diesel generator cannot be confirmed not toexist on the remaining diesel generators, performance of Surveillance 4.8.1.1.2.a.4 suffices to provideassurance to continued OPERABILITY of the other diesel generators.

According to Generic Letter 84-15, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable to confirm that the OPERABLE dieselgenerators are not affected by the same problem as the inoperable diesel generator.

Action f prohibits the application of LCO 3.0.4.b to an inoperable diesel generator.

There is anincreased risk associated with entering a MODE or other specified condition in the Applicability with aninoperable diesel generator and the provisions of LCO 3.0.4.b, which allow entry into a MODE or otherspecified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The OPERABILITY of the minimum specified A.C. and D.C. power sources and associated distribution systems during shutdown and refueling ensures that 1) the facility can be maintained in theshutdown or refueling condition for extended time periods and 2) sufficient instrumentation and controlcapability is available for monitoring and maintaining the unit status.With the minimum required AC power sources not available, it is required to suspend COREALTERATIONS and operations involving positive reactivity additions that could result in loss of requiredSDM (Mode 5) or boron concentration (Mode 6). Suspending positive reactivity additions that could resultin failure to meet minimum SDM or boron concentration limit is required to assure continued safeoperation.

Introduction of coolant inventory must be from sources that have a boron concentration greater than or equal to that required in the RCS for minimum SDM or refueling boron concentration.

This may result in an overall reduction in RCS boron concentration but provides acceptable margin tomaintaining subcritical operation.

Introduction of temperature changes including temperature increases when operating with a positive MTC must also be evaluated to ensure they do not result in a loss ofrequired SDM.The requirements of Specification 3.8.2.1 provide those actions to be taken for the inoperability ofA.C. Distribution Systems.

Action a of this specification provides an 8-hour action for the inoperability ofone or more A.C. boards. Action b of this specification provides a relaxation of the 8-hour action to 24-hours provided the Vital Instrument Power Board is inoperable solely as a result of one inoperable inverter and the board has been energized within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In this condition the requirements of Action ado not have to be applied.

Action b is not intended to provide actions for inoperable inverters, which isDecember 21, 2012SEQUOYAH

-UNIT 1 B 3/4 8-5 Amendment No. 12, 137, 173, 205, 234, 241,261,285, 301 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued) addressed by the operability requirements for the boards, and is included only for relief from the 8-houraction of Action a when only one inverter is affected.

More than one inverter inoperable will result in theinoperability of the associated 120 Volt A.C. Vital Instrument Power Board(s) in accordance with Action a.With more than one inverter inoperable entry into the actions of TS 3.0.3 is not applicable because Actiona includes provisions for multiple inoperable inverters as attendant equipment to the boards.The Surveillance Requirements for demonstrating the OPERABILITY of the diesel generators arein accordance with the recommendations of Regulatory Guides 1.9 "Selection of Diesel Generator SetCapacity for Standby Power Supplies,"

March 10, 1971, and 1.108 "Periodic Testing of Diesel Generator Units Used as Onsite Electric Power Systems at Nuclear Power Plants,"

Revision 1, August 1977, and1.137 "Fuel-Oil Systems for Standby Diesel Generators,"

Revision 1, October 1979. The Surveillance Requirements for the diesel generator load-run test and the 24-hour endurance and margin test are inaccordance with Regulatory Guide 1.9, Revision 3, July 1993, "Selection, Design, Qualification, andTesting of Emergency Diesel Generator Units Used as Class 1 E Onsite Electric Power Systems atNuclear Power Plants."

During the diesel generator endurance and margin surveillance test, momentary transients outside the kw and kvar load ranges do not invalidate the test results.

Similarly, during thediesel generator load-run test, momentary transients outside the kw load range do not invalidate the testresults.Where the SRs discussed herein specify voltage and frequency tolerances, the following isapplicable.

6800 volts is the minimum steady state output voltage and the 10 second transient value.6800 volts is 98.6% of nominal bus voltage of 6900 volts and is based on the minimum voltage requiredfor the diesel generator supply breaker to close on the 6.9 kV Shutdown Board. The specified maximumsteady state output voltage of 7260 volts is based on the degraded over voltage relay setpoint and isequivalent to 110% of the nameplate rating of the 6600 volt motors. The specified minimum andmaximum frequencies of the diesel generator are 58.8 Hz and 61.2 Hz, respectively.

These values areequal to +/- 2% of the 60 Hz nominal frequency and are derived from the recommendations given inregulatory Guide 1.9.Where the SRs discuss maximum transient voltages during load rejection

testing, the following isapplicable.

The maximum transient voltage of 8880 volts represents a conservative limit to ensure theresulting voltage will not exceed a level that will cause component damage. It is based on themanufacturer's recommended high potential test voltage of 60% of the original factory high potential testvoltage (14.8 kV). The diesel generator manufacturer has determined that the engine and/or generator controls would not experience detrimental effects for transient voltages

< 9000 volts. The maximumtransient voltage of 8276 volts is retained from the original technical specifications to ensure that thevoltage transient following rejection of the single largest load is within the limits originally considered acceptable.

It was based on 114% of 7260 volts, which is the Range B service voltage per ANSI-C84.1.

The Surveillance Requirement (SR) to transfer the power supply to each 6.9 kV Unit Board fromthe normal supply to the alternate supply demonstrates the OPERABILITY of the alternate supply topower the shutdown loads. The 18 month Frequency of the Surveillance is based on engineering

judgment, taking into consideration the unit conditions required to perform the Surveillance, and isintended to be consistent with expected fuel cycle lengths.

Operating experience has shown that thesecomponents usually pass the SR when performed at the 18 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by two Notes. Thereason for Note # is that, during operation with the reactor critical, performance of this SR for the Unit 1Unit Boards could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, unit safety systems.

Note ## specifies that transferDecember 21, 2012SEQUOYAH

-UNIT 1 B 3/4 8-6 Amendment No. 12, 137,173, 205, 234,261,285, 332 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued) capability is only required to be met for 6.9 kV Unit Boards that require normal and alternate powersupplies.

When both load groups are being supplied power by the USSTs, only the 6.9 kV Unit Boardsassociated with one load group are required to have normal and alternate power supplies.

Therefore, only one CSST is required to be OPERABLE and available as an alternate power supply. Additionally, manual transfers between the normal supply and the alternate supply are not relied upon to meet theaccident analysis.

Manual transfer capability is verified to ensure the availability of a backup to theautomatic transfer feature.The Surveillance Requirement for demonstrating the OPERABILITY of the Station batteries arebased on the recommendations of Regulatory Guide 1.129 "Maintenance Testing and Replacement ofLarge Lead Storage Batteries for Nuclear Power Plants,"

February 1978, and IEEE Std 450-1980, "IEEERecommended Practice for Maintenance,

Testing, and Replacement of Large Lead Storage batteries forGenerating Stations and Substations."

Verifying average electrolyte temperature above the minimum for which the battery was sized,total battery terminal voltage onfloat charge, connection resistance values and the performance of batteryservice and discharge tests ensures the effectiveness of the charging system, the ability to handle highdischarge rates and compares the battery capacity at that time with the rated capacity.

Table 4.8-2 specifies the normal limits for each designated pilot cell and each connected cell forelectrolyte level, float voltage and specific gravity.

The limits for the designated pilot cells float voltageand specific

gravity, greater than 2.13 volts and .015 below the manufacturer's full charge specific gravityor a battery charger current that had stabilized at a low value, is characteristic of a charged cell withadequate capacity.

The normal limits for each connected cell for float voltage and specific

gravity, greaterthan 2.13 volts and not more than .020 below the manufacturer's full charge specific gravity with anaverage specific gravity of all the connected cells not more than .010 below the manufacture's full chargespecific

gravity, ensures the OPERABILITY and capability of the battery.Operation with a battery cell's parameter outside the normal limit but within the allowable valuespecified in Table 4.8-2 is permitted for up to 7 days. During this 7 day period: (1) the allowable valuesfor electrolyte level ensures no physical damage to the plates with an adequate electron transfercapability; (2) the allowable value for the average specific gravity of all the cells, not more than .020 belowthe manufacturer's recommended full charge specific

gravity, ensures that the decrease in rating will beless than the safety margin provided in sizing; (3) the allowable value for an individual cell's specificgravity, ensures that an individual cell's specific gravity will not be more than .040 below themanufacturer's full charge specific gravity and that the overall capability of the battery will be maintained within an acceptable limit; and (4) the allowable value for an individual cell's float voltage, greater than2.07 volts, ensures the battery's capability to perform its design function.

The tests listed below are a means of determining whether new fuel oil is of the appropriate gradeand has not been contaminated with substances that would have an immediate, detrimental impact ondiesel engine combustion.

If the results from these tests are within acceptable limits, the fuel oil may beadded to the storage tanks without concern for contaminating the entire volume of fuel oil in the storagetanks. These tests are to be conducted prior to adding the new fuel to the storage tank(s),

but in no caseis the time between receipt of new fuel and conducting the tests to exceed 31 days. The test, limits, andapplicable ASTM Standards are as follows:December 21, 2012SEQUOYAH

-UNIT 1 B 3/4 8-7 Amendment No. 12, 137, 173, 205, 234,250, 261,332 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

a. Sample the new fuel in accordance with D4057-1988 (ref.);b. Verify in accordance with the test specified in ASTM D975-1990 (Ref.) that the sample has anabsolute specific gravity at 60/60 degrees F of __ 0.83 and _< 0.89 or an API gravity at 60 degrees F of> 27 degrees and < 39 degrees, a kinematic viscosity at 40 degrees C of >_ 1.9 centistokes and < 4.1centistokes, and a flash point of _> 125 degrees F; andc. Verify that the new fuel oil has a clear and bright appearance with proper color when tested inaccordance with ASTM D4176-1986 (Ref.).Failure to meet any of the above limits is cause for rejecting the new fuel oil, but does not represent afailure to meet LCO concern since the fuel oil is not added to the storage tanks.Within 31 days following the initial new fuel oil sample, the fuel oil is analyzed to establish that theother properties specified in Table 1 of ASTM D975-1990 (Ref.) are met, except that the analysis forsulfur may be performed in accordance with ASTM D1552-1990 (Ref.) or ASTM D2622-1987 (Ref.). The31 day period is acceptable because the fuel oil properties of interest, even if they were not within statedlimits, would not have an immediate effect on DIG operation.

This surveillance ensures availability of highquality fuel oil for the D/Gs.Fuel oil degradation during long-term storage shows up as an increase in particulate, due mostly tooxidation.

The presence of particulate does not mean the fuel oil will not burn properly in a diesel engine.The particulate can cause fouling of filters and fuel oil injection equipment,

however, which can causeengine failure.Particulate concentrations should be determined in accordance with ASTM D2276-94, Method A(Ref.). This method involves a gravimetric determination of total particulate concentration in the fuel oiland has a limit of 10 mg/l. It is acceptable to obtain a field sample for subsequent laboratory testing inlieu of field testing.

Each of the four interconnected tanks which comprise a 7-day tank must beconsidered and tested separately.

The frequency of this test takes into consideration fuel oil degradation trends that indicate thatparticulate concentration is unlikely to change significantly between frequency intervals.

References:

ASTM Standards D4057-1988, "Practice for manual sampling of petroleum and petroleum Products."

D975-1990, "Standard Specifications for Diesel Fuel oils."D4176-1986, "Free Water and Particulate Contamination in Distillate Fuels."D1552-1990, "Standard Test Method for Sulfur in Petroleum Products (High Temperature Method)."

December 21, 2012SEQUOYAH

-UNIT 1 B 3/4 8-8 Amendment No.12, 137, 250, 261 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

D2622-1987, "Standard Test Method for Sulfur in Petroleum Products (X-Ray Spectrographic Method)."

D2276-1994, "Standard Test Method for Particulate Containment in Aviation Turbine Fuels."D1298-1985, "Standard Test Method for Density, Specific

Gravity, or API Gravity of Crude Petroleum andLiquid Petroleum Products by Hydrometer Method."3/4.8.3 ELECTRICAL EQUIPMENT PROTECTIVE DEVICESThis specification is deleted.December 21, 2012Amendment No.12, 137, 250, 261SEQUOYAH

-UNIT 1B 3/4 8-9 ATTACHMENT 3SEQUOYAH NUCLEAR PLANT, UNIT 2TECHNICAL SPECIFICATION BASESCHANGED PAGESTS Bases Affected PagesEPL Page 2EPL Page 3EPL Page 16EPL Page 17EPL Page 19EPL Page 20EPL Page 21EPL Page 22EPL Page 31EPL Page 32Index Page IIIIndex Page XIVB 2-1B 2-2B 2-3B 2-4B 2-5B 2-6B 2-7B 2-8B 2-9B 2-10B 2-11B 3/4 2-4B 3/4 3-3aB 3/4 4-3aB 3/4 4-3bB 3/4 4-3cB 3/4 4-3dB 3/4 4-3eB 3/4 4-3fB 3/4 4-3gRemoved B 3/4 4-3hthrough B 3/4 4-3kB 3/4 4-4fB 3/4 5-12B 3/4 5-13B 3/4 5-14B 3/4 5-15B 3/4 5-16B 3/4 5-17B 3/4 5-18B 3/4 5-19B 3/4 5-20B 3/4 8-1B 3/4 8-2B 3/4 8-3B 3/4 8-4B 3/4 8-5B 3/4 8-6B 3/4 8-7B 3/4 8-8B 3/4 8-9 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaqe RevisionIndex Page VII 01/28/10Index Page VIII 12/28/05Index Page IX 12/28/05Index Page X 12/28/05Index Page XI 12/18/00-Index Page XII 03/09/05Index Page XIII 01/28/10Index Page XIV 12/21/12Index Page XV 12/18/00Index Page XVI 08/02/06Index Page XVII 05/24/021-1 05/18/881-2 04/13/091-3 02/29/001-4 05/22/071-5 05/22/071-6 08/02/061-7 09/15/041-8 09/15/041-9 05/18/881-10 05/18/882-1 09/26/122-2 09/26/122-3 (DELETED) 09/03/85EPL-2December 21, 2012 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaqe Revision2-4 09/13/062-5 09/26/122-6 09/13/062-7 09/20/072-8 09/13/062-9 09/13/062-10 09/13/062-11 09/13/062-12 09/13/06B(Note) OriginalB2-1 10/10/12B2-2 10/10/12B2-3 10/10/12B2-4 10/10/12B2-5 10/10/12B2-6 10/10/12B2-7 10/10/12B2-8 10/10/12B2-9 10/10/12B2-10 10/10/12B2-11 10/10/123/4 0-1 10/04/063/4 0-2 10/04/063/4 0-3 10/04/063/4 0-4 10/04/063/4 1-1 11/26/933/4 1-2 Original3/4 1-3 11/26/93EPL-3October 10, 2012 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaae RevisionB3/4 0-4 02/05/03B3/4 0-5 06/16/06B3/4 0-6 06/16/06B3/4 1-1 10/26/93B3/4 1-2 12/18/00B3/4 1-3 12/18/00B3/4 1-3a 03/07/07B3/4 1-4 04/21/97B3/4 1-4a 11/21/95B3/4 2-1 04/21/97B3/4 2-2 04/21/97B3/4 2-3 (Figure B3/4 2-1 DELETED) 09/29/83B3/4 2-4 10/10/12B3/4 3-1 09/13/06B3/4 3-2 09/13/06B3/4 3-2a 08/29/08B3/4 3-3 12/28/05B3/4 3-3a 03/05/13B3/4 3-4 08/12/97B3/4 3-5 through B3/4 3-9 09/14/06B3/4 4-1 03/30/92B3/4 4-2 06/16/06B3/4 4-2a 05/25/00B3/4 4-3 05/22/07EPL-16March 5, 2013 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPage RevisionB3/4 4-3a 10/05/12B3/4 4-3b 10/05/12B3/4 4-3c 10/05/12B3/4 4-3d 10/05/12B3/4 4-3e 10/05/12B3/4 4-3f 10/05/12B3/4 4-3g 10/05/12B3/4 4-3h (Deleted) 10/05/12B3/4 4-3i (Deleted) 10/05/12B3/4 4-3j (Deleted) 10/05/12B3/4 4-3k (Deleted) 10/05/12B3/4 4-4 12/04/08B3/4 4-4a 12/04/08B3/4 4-4b 04/11/05B3/4 4-4c 12/04/08B3/4 4-4d 12/04/08B3/4 4-4e 05/22/07B3/4 4-4f 10/05/12B3/4 4-4g 05/22/07B3/4 4-4h 05/22/07B3/4 4-4i 05/22/07B3/4 4-4j 05/22/07B3/4 4-4k 08/04/00B3/4 4-41 08/04/00EPL-17October 5, 2012 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPa_qe RevisionB3/4 5-1 03/25/1083/4 5-2 03/25/10B3/4 5-3 03/25/1083/4 5-4 03/25/10B3/4 5-5 03/25/10B3/4 5-6 03/25/10B3/4 5-7 03/25/10B3/4 5-8 through B3/4 5-11 03/25/10B3/4 5-12 through B3/4 5-20 03/24/12B3/4 6-1 through 83/4 6-2 04/13/09B3/4 6-3 05/27/10B3/4 6-4 through B3/4 6-6 04/13/09B3/4 6-7 through B3/4 6-12 04/13/09B3/4 6-13 through B3/4 6-18 04/13/09B3/4 6-19 through B3/4 6-20 04/13/0983/4 6-21 04/13/0983/4 7-1 04/30/0283/4 7-2 08/14/01B3/4 7-2a 11/17/95B3/4 7-2b 04/11/0583/4 7-3 06/12/09EPL-1 9March 24, 2012 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPage RevisionB3/4 7-3a 06/08/98B3/4 7-4 09/28/07B3/4 7-4a 09/28/07B3/4 7-4b 09/28/07B3/4 7-4c thru B3/4 7-4m 10/28/08B3/4 7-5 08/18/05B3/4 7-6 (DELETED) 08/28/98B3/4 7-6a 12/28/05B3/4 7-7 through B3/4 7-8 (DELETED) 08/12/97B3/4 7-9 12/19/00B3/4 7-10 12/19/00B3/4 7-11 12/19/00B3/4 7-12 12/19/00B3/4 7-13 12/19/00B3/4 7-14 12/19/00B3/4 7-15 12/19/00B3/4 7-16 01/31/05B3/4 7-17 02/27/02B3/4 7-18 02/27/02B3/4 8-1 12/21/12B3/4 8-2 12/21/12B3/4 8-3 12/21/12B3/4 8-4 12/21/12B3/4 8-5 12/21/12B3/4 8-6 12/21/12B3/4 8-7 12/21/12B3/4 8-8 12/21/12B3/4 8-9 12/21/12EPL-20December 21, 2012 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaqe RevisionB3/4 9-1 09/20/04B3/4 9-2 12/28/05B3/4 9-3 04/19/04B3/4 10-1 09/20/04B3/4 11-1 12/09/93B3/4 11-2 11/16/9083/4 12-1 11/16/905-1 08/02/065-2 08/02/065-3 08/02/065-4 08/02/065-5 12/19/005-5a 12/19/005-5b 08/02/065-5c 12/19/005-5d 12/19/005-5e 12/19/005-5f 12/19/005-5g 12/19/005-5h 12/19/005-5i 12/19/005-5j 12/19/005-6 08/02/06EPL-21December 21, 2012 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS EFFECTIVE PAGE LISTINGPaqe Revision6-1 02/16/016-2 02/02/106-3 through 6-4 (DELETED) 02/16/016-5 02/11/036-6 05/24/026-7 02/11/036-8 02/11/036-9 04/13/096-10 04/13/096-10a 07/10/126-1Ob 07/10/126-1 Oc (Deleted) 07/10/126-10d (Deleted) 07/10/12.6-11 04/13/096-12 08/02/936-13 09/26/126-14 09/26/126-14a 09/26/126-15 07/10/126-16 02/11/036-16a 02/11/036-16b 02/11/036-17 07/01/986-18 02/11/036-19 10/28/086-20 10/28/08EPL-22September 26, 2012 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Amendment 288 Issued by NRCAmendment 289 Issued by NRCAmendment 290 Issued by NRCAmendment 291 Issued by NRCAmendment 292 Issued by NRCAmendment 293 Issued by NRCAmendment 294 Issued by NRCBases RevisionAmendment 295 Issued by NRCAmendment 296 Issued by NRCAmendment 297 Issued by NRCAmendment 298 Issued by NRCAmendment 299 Issued by NRCAmendment 300 Issued by NRCAmendment 301 Issued by NRCAmendment 302 Issued by NRCAmendment 303 Issued by NRCAmendment 304 Issued by NRCLicense Condition Issued by NRCBases RevisionAmendment 305 Issued by NRCEPL RevisedLicense Condition Issued by NRCAmendment 306 Issued by NRCAmendment 307 Issued by NRCAmendment 308 Issued by NRCBases RevisionAmendment 309 Issued by NRCAmendment 310 Issued by NRCAmendment 311 Issued by NRCAmendment 312 Issued by NRCBases RevisionBases RevisionAmendment 313 Issued by NRCAmendment 314 Issued by NRCAmendment 315 Issued by NRCAmendment 316 Issued by NRCBases RevisionAmendment 317 Issued by NRCAmendment 318 Issued by NRCBases RevisionAmendment 319 Issued by NRCAmendment 320 Issued by NRCBases RevisionBases RevisionAmendment 321 Issued by NRCBases RevisionAmendment 323 Issued by NRCBases RevisionAmendment 324 Issued by NRCBases RevisionDate and Revision03/09/05 (R288)04/05/05 (R289)04/11/05 (R290)05/03/05 (R291)05/24/05 (R292)08/18/05 (R293)09/02/05 (R294)09/11/03 (BR-28)12/28/05 (R295)04/06/06 (R296)06/16/06 (R297)08/02/06 (R298)09/13/06 (R299)09/14/06 (R300)10/04/06 (R301)11/07/06 (R302)11/16/06 (R303)12/11/06 (R304)02/08/0703/07/07 (BR-29)05/22/07 (R305)05/22/0708/09/07 (B.5.b)09/20/07 (R306)09/28/07 (R307)10/11/07 (R308)12/12/07 (BR-30)03/24/08 (R309)04/02/08 (R310)04/04/08 (R31 1)08/29/08 (R312)08/29/08 (BR-31)08/28/08 (BR-32)10/28/0812/04/0804/13/0906/12/0906/12/09 (BR-33)08/14/0910/19/0910/19/09 (BR-34)01/28/1002/02/1003/25/10 (BR-35)05/27/10 (BR-36)12/21/1003/24/12 (BR-38)07/10/1210/05/12 (BR-40)09/26/1210/10/12 (BR-39)EPL-31October 10, 2012 SEQUOYAH NUCLEAR PLANT UNIT 2TECHNICAL SPECIFICATIONS AMENDMENT LISTINGAmendments Amendment 325 Issued by NRCBases RevisionBases RevisionDate and Revision10/31/1212/21/12 (BR-41)03/05/13 (BR-42)EPL-32March 5, 2013 INDEXSAFETY LIMITS AND LIMITING SAFETY SYSTEM SETTINGSSECTION PAGE2.1 SAFETY LIMITSR e a c to r C o re ...................................................................................................................................

2 -1R eactor C oolant S ystem Pressure

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2-12.2 LIMITING SAFETY SYSTEM SETTINGSReactor Trip System Instrumentation Setpoints

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2-4BASESSECTIONPAGE2.1 SAFETY LIMITSR e a c to r C o re ..............................................................................................................................

B 2 -1Reactor Coolant System Pressure

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B 2-22.2 LIMITING SAFETY SYSTEM SETTINGSReactor Trip System Instrum entation Setpoints

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B 2-3SEQUOYAH

-UNIT 2IIIOctober 10, 2012Amendment No. 324 INDEXBASESSECTION PAGE3/4.7.4 ESSENTIAL RAW COOLING WATER SYSTEM .............................................................

B 3/4 7-3a3/4.7.5 U LT IM A T E H EA T S IN K ......................................................................................................

B 3/4 7-43/4.7.6 FLO O D P R O T EC T IO N .......................................................................................................

B 3/4 7-43/4.7.7 CONTROL ROOM EMERGENCY VENTILATION SYSTEM .............................................

B 3/4 7-43/4.7.8 AUXILIARY BUILDING GAS TREATMENT SYSTEM .......................................................

B 3/4 7-53/4 .7 .9 S N U B B E R S ........................................................................................................................

B 3/4 7 -53/4.7.10 SEALED SOURCE CONTAMINATION (DELETED)

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B 3/4 7-6a3/4.7.11 FIRE SUPPRESSION SYSTEMS (DELETED)

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B 3/4 7-73/4.7.12 FIRE BARRIER PENETRATIONS (DELETED)

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B 3/4 7-83/4.7.13 SPENT FUEL POOL MINIMUM BORON CONCENTRATION

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B 3/4 7-93/4.7.14 CASK PIT POOL MINIMUM BORON CONCENTRATION

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B 3/4 7-133/4.7.15 CONTROL ROOM AIR-CONDITIONING SYSTEM (CRACS) .........................................

B 3/4 7-163/4.8 ELECTRICAL POWER SYSTEMS3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION S Y S T E M S ...........................................................................................................................

B 3 /4 8 -13/4.8.3 ELECTRICAL EQUIPMENT PROTECTIVE DEVICES (DELETED)

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B 3/4 8-93/4.9 REFUELING OPERATIONS 3/4.9.1 BO RO N C O NC ENTRATIO N ..............................................................................................

B 3/4 9-13/4.9.2 IN ST R U M E N TA T IO N .........................................................................................................

B 3/4 9-13/4 .9 .3 D E C A Y T IM E ......................................................................................................................

B 3/4 9-13/4.9.4 CONTAINMENT BUILDING PENETRATIONS

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B 3/4 9-13/4.9.5 CO M M UN ICATIO NS (Deleted)

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B 3/4 9-23/4.9.6 M ANIPULATO R C RANE (Deleted)

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B 3/4 9-23/4.9.7 CRANE TRAVEL -SPENT FUEL PIT AREA (DELETED)

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B 3/4 9-23/4.9.8 RESIDUAL HEAT REMOVAL AND COOLANT CIRCULATION

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B 3/4 9-23/4.9.9 CONTAINMENT VENTILATION SYSTEM .........................................................................

B 3/4 9-3December 21, 2012SEQUOYAH

-UNIT 2 XIV Amendment No. 194, 218, 225, 256,262, 295,325 2.1 SAFETY LIMITSBASES2.1.1 REACTOR COREThe restrictions of this Safety Limit prevent overheating of the fuel cladding (due to departure from nucleate boiling) and overheating of the fuel pellet (centerline fuel melt), either of which could resultin cladding perforation that would result in the release of fission products to the reactor coolant.Overheating of the fuel cladding is prevented by restricting fuel operation to within the nucleate boilingregime where the heat transfer coefficient is large and the cladding surface temperature is slightly abovethe coolant saturation temperature.

Overheating of the fuel is prevented by maintaining the steady statepeak linear heat rate (LHR) below the level at which fuel centerline melting occurs.Operation above the upper boundary of the nucleate boiling regime could result in excessive temperatures because of the onset of departure from nucleate boiling (DNB) and the corresponding significant reduction in heat transfer coefficient from the outer surface of the cladding to the reactorcoolant water. Inside the steam film, high cladding temperatures are reached, and a cladding water(zirconium water) reaction may take place. This chemical reaction results in oxidation of the fuel claddingto a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled releaseof activity to the reactor coolant.

DNB is not a directly measurable parameter during operation and;therefore, THERMAL POWER and Reactor Coolant Temperature and Pressure have been related toDNB. The DNB correlations have been developed to predict the DNB flux and the location of DNB foraxially uniform and non-uniform heat flux distributions.

The local DNB heat flux ratio, DNBR, defined asthe ratio of the heat flux that would cause DNB at a particular core location to the local heat flux, isindicative of the margin to DNB.The DNB design basis is that there must be at least a 95 percent probability with 95 percentconfidence that DNB will not occur when the minimum DNBR is at the design DNBR limit.To meet the DNB Design Basis, a statistical core design (SCD) process has been used todevelop an appropriate statistical DNBR design limit. Uncertainties in plant operating parameters, nuclear and thermal parameters, and fuel fabrication parameters are considered statistically such thatthere is at least a 95 percent probability at a 95 percent confidence level that the minimum DNBR for thelimiting rod is greater than or equal to the DNBR limit. This DNBR uncertainty derived from the SCDanalysis, combined with the applicable DNB critical heat flux correlation limit, establishes the statistical DNBR design limit which must be met in plant safety analysis using values of input parameters withoutadjustment for uncertainty.

The curves of Figure 2.1-1 show the loci of points of THERMAL POWER, Reactor CoolantSystem pressure and average temperature for which the minimum DNBR is no less than the safetyanalysis DNBR limit, or the average enthalpy at the vessel exit is equal to the enthalpy of saturated liquid.These lines are bounding for all fuel types. The curves in Figure 2.1-1 are based upon enthalpy rise hotchannel factors that result in acceptable DNBR performance of each fuel type. Acceptable DNBRperformance is assured by operation within the DNB-based Limiting Safety Limit System Settings (RPStrip limits).

The plant trip setpoints are verified to be less than the limits defined by the safety limit lines inFigure 2.1-1 converted from power to delta-temperature and adjusted for uncertainty.

October 10, 2012SEQUOYAH

-UNIT 2 B 2-1 Amendment No. 21, 104,130,146, 214, 324 2.1 SAFETY LIMITSBASESOperation above the maximum local linear heat generation rate for fuel melting could result inexcessive fuel pellet temperature and cause melting of the fuel at its centerline.

Fuel centerline meltingoccurs when the local LHR, or power peaking, in a region of the fuel is high enough to cause the fuelcenterline temperature to reach the melting point of the fuel. Expansion of the pellet upon centerline melting may cause the pellet to stress the cladding to the point of failure, allowing an uncontrolled releaseof activity to the reactor coolant.

The melting point of uranium dioxide varies slightly with burnup. Asuranium is depleted and fission products

produced, the net effect is a decrease in the melting point. Fuelcenterline temperature is not a directly measurable parameter during operation.

The maximum local fuelpin centerline temperature is maintained by limiting the local linear heat generation rate in the fuel. Thelocal linear heat generation rate in the fuel is limited so that the maximum fuel centerline temperature willnot exceed the acceptance criteria in the safety analysis.

The limiting heat flux conditions for DNB are higher than those calculated for the range of allcontrol rods fully withdrawn to the maximum allowable control rod insertion assuming the axial powerimbalance, or Delta-I (Al), is within the limits of the f, (Al) function of the Overtemperature Delta-Temperature trip. When the axial power imbalance exceeds the tolerance (or deadband) of the f, (AI) tripreset function, the Overtemperature Delta-Temperature trip setpoint is reduced by the values in theCORE OPERATING LIMITS REPORT to provide protection required by the core safety limits.Similarly, the limiting linear heat generation rate conditions for centerline fuel melt are higher thanthose calculated for the range of all control rods from the fully withdrawn to the maximum allowable control rod insertion assuming the axial power imbalance, or Delta-I (Al), is within the limits of the f2 (Al)function of the Overpower Delta-Temperature trip. When the axial power imbalance exceeds thetolerance (or deadband) of the f2 (AI) trip resent function, the Overpower Delta-Temperature trip setpointis reduced by the values specified in the CORE OPERATING LIMITS REPORT to provide protection required by the core safety limits.2.1.2 REACTOR COOLANT SYSTEM PRESSUREThe restriction of this Safety Limit protects the integrity of the Reactor Coolant System fromoverpressurization and thereby prevents the release of radionuclides contained in the reactor coolantfrom reaching the containment atmosphere.

The reactor pressure vessel and pressurizer are designed to Section III of the ASME Code forNuclear Power Plant which permits a maximum transient pressure of 110% (2735 psig) of designpressure.

The Reactor Coolant System piping, valves and fittings, are designed to ANSI B 31.1 1967Edition, which permits a maximum transient pressure of 120% (2985 psig) of component design pressure.

The Safety Limit of 2735 psig is therefore consistent with the design criteria and associated coderequirements.

,The entire Reactor Coolant System is hydrotested at 3107 psig, 125% of design pressure, todemonstrate integrity prior to initial operation.

October 10, 2012SEQUOYAH

-UNIT 2 B 2-2 Amendment No. 324 SAFETY LIMITSBASES2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS The Reactor Nominal Trip Setpoint Limits specified in Table 2.2-1 are the values at which theReactor Trips are set for each functional unit. The Nominal Trip Setpoints have been selected to ensurethat the reactor core and reactor coolant system are prevented from exceeding their safety limits duringnormal operation and design basis anticipated operational occurrences and to assist the Engineered Safety Features Actuation System in mitigating the consequences of accidents.

Operation with a trip setless conservative than its Nominal Trip Setpoint but within its specified Allowable Value is acceptable onthe basis that the difference between each Nominal Trip Setpoint and the Allowable Value is equal to orless than the rack allowance assumed for each trip in the safety analyses.

Technical specifications are required by 10 CFR 50.36 to contain Limiting Safety System Settings(LSSS) defined by the regulation as "... settings for automatic protective devices...

so chosen thatautomatic protective action will correct the abnormal situation before a Safety Limit (SL) is exceeded."

The analytic limit is the limit of the process variable at which a safety action is initiated, as established bythe safety analysis, to ensure that a SL is not exceeded.

Any automatic protection action that occurs onreaching the analytic limit therefore ensures that the SL is not exceeded.

However, in practice, the actualsettings for automatic protective devices must be chosen to be more conservative than the analytic limitto account for instrument loop uncertainties related to the setting at which the automatic protective actionwould actually occur.The Nominal Trip Setpoint is a predetermined setting for a protective device chosen to ensureautomatic actuation prior to the process variable reaching the analytic limit and thus ensuring that the SLwould not be exceeded.

As such, the Nominal Trip Setpoint accounts for uncertainties in setting thedevice (e.g., calibration),

uncertainties in how the device might actually perform (e.g., repeatability),

changes in the point of action of the device over time (e.g., drift during surveillance intervals),

and anyother factors which may influence its actual performance (e.g., harsh accident environments).

In thismanner, the Nominal Trip Setpoint plays an important role in ensuring that SLs are not exceeded.

Assuch, the Nominal Trip Setpoint meets the definition of an LSSS in accordance with Regulatory Guide1.105, Revision 3, "Setpoints for Safety-Related Instrumentation,"

and could be used to meet therequirements that they be contained in the technical specifications.

October 10, 2012SEQUOYAH

-UNIT 2 B 2-3 Amendment No. 130, 146, 299, 324 SAFETY LIMITSBASES2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS (Continued)

Technical specifications contain values related to the OPERABILITY of equipment required forsafe operation of the facility.

OPERABLE is defined in the technical specifications as ". ..being capableof performing its safety function(s)."

For automatic protective

devices, the required safety function is toensure that a SL is not exceeded and therefore the LSSS as defined by 10 CFR 50.36 is the same as theOPERABILITY limit for these devices.

However, use of the Nominal Trip Setpoint to defineOPERABILITY in technical specifications and its corresponding designation as the LSSS required by 10CFR 50.36 would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the"as found" value of a protective device setting during a surveillance.

This would result in technical specification compliance

problems, as well as reports and corrective actions required by the rule whichare not necessary to ensure safety. For example, an automatic protective device with a setting that hasbeen found to be different from the Nominal Trip Setpoint due to some drift of the setting may still beOPERABLE since drift is to be expected.

This expected drift would have been specifically accounted forin the setpoint methodology for calculating the Nominal Trip Setpoint and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of theprotective device. Therefore, the device would still be OPERABLE since it would have performed itssafety function and the only corrective action required would be to reset the device to the Nominal TripSetpoint to account for further drift during the next surveillance interval.

Use of the Nominal Trip Setpoint to define "as found" OPERABILITY and its designation as theLSSS under the expected circumstances described above would result in actions required by both therule and technical specifications that are clearly not warranted.

However, there is also some pointbeyond which the device would have not been able to perform its function due, for example, to greaterthan expected drift. This value needs. to be specified in the technical specifications in order to defineOPERABILITY of the devices and is designated as the Allowable Value, which as stated above, is thesame as the LSSS.The Allowable Value specified in Table 2.2-1 serves as the LSSS such that a channel isOPERABLE if the trip setpoint is found not to exceed the Allowable Value during the CHANNELFUNCTIONAL TEST (CFT). As such, the Allowable Value differs from the Nominal Trip Setpoint by anamount primarily equal to the expected instrument loop uncertainties, such as drift, during thesurveillance interval.

In this manner, the actual setting of the device will still meet the LSSS definition andensure that a Safety Limit is not exceeded at any given point of time as long as the device has not driftedbeyond that expected during the surveillance interval.

Note that, although the channel is "OPERABLE" under these circumstances, the trip setpoint should be left adjusted to a value within the established tripsetpoint calibration tolerance band, in accordance with uncertainty assumptions stated in the setpointmethodology (as-left criteria),

and confirmed to be operating within the statistical allowances of theuncertainty terms assigned.

If the actual setting of the device is found to have exceeded the Allowable Value, the device would be considered inoperable from a technical specification perspective.

Thisrequires corrective action including those actions required by 10 CFR 50.36 when automatic protective devices do not function as required.

A channel is OPERABLE with a trip setpoint value outside its calibration tolerance band providedthe trip setpoint "as-found" value does not exceed its associated Allowable Value and provided the tripsetpoint "as-left" value is adjusted to a value within the "as-left" calibration tolerance band of the NominalTrip Setpoint.

A trip setpoint may be set more conservative than the Nominal Trip Setpoint as necessary in response to plant conditions.

The conservative direction is established by the direction of the inequality applied to the Allowable Value.A detailed description of the methodology used to calculate the Allowable Value and trip setpoints, including their explicit uncertainties, is provided in the Westinghouse Electric Company setpointmethodology study which incorporates all of the known uncertainties applicable to each channel.

Themagnitudes of these uncertainties are factored into the determination of each trip setpoint andOctober 10, 2012SEQUOYAH

-UNIT 2 B 2-4 Amendment No. 299 SAFETY LIMITSBASES2.2.1 REACTOR TRIP SYSTEM INSTRUMENTATION SETPOINTS (Continued) corresponding Allowable Value. The trip setpoint entered into the channel is more conservative than thatspecified by the Allowable Value (LSSS) to account for measurement errors detectable by the CFT. TheAllowable Value serves as the Technical Specification OPERABILITY limit for the purpose of the CFT.One example of such a change in measurement error is drift during the surveillance interval.

If themeasured setpoint does not exceed the Allowable Value, the channel is considered OPERABLE.

The trip setpoint is the value at which the channels are set and is the expected value to beachieved during calibration.

The trip setpoint value ensures the LSSS and safety analysis limits are metfor the surveillance interval selected when a channel is adjusted based on the stated channeluncertainties.

Any channel is considered to be properly adjusted when the "as-left" setpoint value iswithin the band for CHANNEL CALIBRATION uncertainty allowance (i.e. +/- rack calibration

+ comparator setting uncertainties).

The trip setpoint value is therefore, considered a "nominal" value (i.e., expressed as a value without inequalities) for the purposes of the CFT and CHANNEL CALIBRATION.

October 10, 2012SEQUOYAH

-UNIT 2 B 2-5 Amendment No. 299 2.2 LIMITING SAFETY SYSTEM SETTINGSBASESManual Reactor TripThe Manual Reactor Trip is a redundant channel to the automatic protective instrumentation channels and provides a manual reactor trip capability.

Power Range, Neutron FluxThe Power Range, Neutron Flux channel high setpoint provides reactor core protection againstreactivity excursions which are too rapid to be protected by temperature and pressure protective circuitry.

The low set point provides redundant protection in the power range for a power excursion beginning fromlow power. The trip associated with the low setpoint may be manually bypassed when P-10 is active (twoof the four power range channels indicate a power level of above approximately 10 percent of RATEDTHERMAL POWER) and is automatically reinstated when P-10 becomes inactive (three of the fourchannels indicate a power level below approximately 9 percent of RATED THERMAL POWER).Power Range, Neutron Flux, High RatesThe Power Range Positive Rate trip provides protection against rapid flux increases which arecharacteristic of rod ejection events from any power level. Specifically, this trip complements the PowerRange Neutron Flux High and Low trips to ensure that the criteria are met for rod ejection from partialpower.The Power Range Negative Rate trip provides protection to ensure that the minimum DNBR ismaintained above the safety analysis DNBR limit for control rod drop accidents.

At high power a single ormultiple rod drop accident could cause local flux peaking which, when in conjunction with nuclear powerbeing maintained equivalent to turbine power by action of the automatic rod control system, could causean unconservative local DNBR to exist. The Power Range Negative Rate trip will prevent this fromoccurring by tripping the reactor for all single dropped rods with a reactivity insertion of greater than500 pcm or multiple dropped rods.Intermediate and Source Range, Nuclear FluxThe Intermediate and Source Range, Nuclear Flux trips provide reactor core protection duringreactor startup.

These trips provide redundant protection to the low setpoint trip of the Power Range,Neutron Flux channels.

The Source Range Channels will initiate a reactor trip at about 10÷5 counts persecond unless manually blocked when P-6 becomes active. The Intermediate October 10, 2012SEQUOYAH

-UNIT 2 B 2-6 Amendment No. 129, 130 LIMITING SAFETY SYSTEM SETTINGSBASESIntermediate and Source Range, Nuclear Flux (Continued)

Range Channels will initiate a reactor trip at approximately 25 percent of RATED THERMAL POWERunless manually blocked when P-10 becomes active. No credit was taken for operation of the tripsassociated with either the Intermediate or Source Range Channels in the accident analyses; however,their functional capability at the specified trip settings is required by this specification to enhance theoverall reliability of the Reactor Protection System.Overtemperature ATThe Overtemperature Delta T trip provides core protection to prevent DNB for all combinations ofpressure, power, coolant temperature, and axial power distribution, provided that the transient is slow withrespect to transit, thermowell, and RTD response time delays from the core to the temperature detectors (about 8 seconds),

and pressure is within the range between the High and Low Pressure reactor trips.This setpoint includes corrections for axial power distribution, changes in density and heat capacity ofwater with temperature and dynamic compensation for transport, thermowell, and RTD response timedelays from the core to the RTD output indication.

With normal axial power distribution, this reactor triplimit is always below the core safety limit as shown in Figure 2.1-1. If axial peaks are greater than design,as indicated by the difference between top and bottom power range nuclear detectors, the reactor trip isautomatically reduced according to the notations inTable 2.2-1.The f1(AI) trip reset term in the Overtemperature Delta T trip function precludes power distributions thatcause the DNB limit to be exceeded during a limiting Condition II event. The negative and positive Allimits at which the f1(AI) term begins to reduce the trip setpoint and the dependence of f1(AI) onTHERMAL POWER are determined on a cycle-specific basis using approved methodology and arespecified in the COLR per Specification 6.9.1.14.

Operation with a reactor coolant loop out of service below the 4 loop P-8 setpoint does not require reactorprotection system setpoint modification because the P-8 setpoint and associated trip will prevent DNBduring 3 loop operation exclusive of the Overtemperature Delta T setpoint.

Delta-To, used in the Overtemperature and Overpower AT trips, represents the 100 percent RTP value asmeasured by the plant for each loop. This normalizes each loop's AT trips to the actual operating conditions existing at the time of measurement, thus forcing the trip to reflect the equivalent full powerconditions as assumed in the accident analyses.

These differences in RCS loop AT can be due toseveral factors, e.g., measured RCS loop flows greater than thermal design flow, and slightly asymmetric power distributions between quadrants.

While RCS loop flows are not expected to change with cycle life,radial power redistribution between quadrants may occur, resulting in small changes in loop specific ATvalues. Accurate determination of the loop specific AT value should be made quarterly and under steadystate conditions (i.e., power distributions not affected by xenon or other transient conditions.).

October 10, 2012SEQUOYAH

-UNIT 2 B 2-7 Amendment No. 129, 132, 214 LIMITING SAFETY SYSTEM SETTINGSBASESOverpower ATThe Overpower Delta T reactor trip provides assurance of fuel integrity, e.g., no melting, under allpossible overpower conditions, limits the required range for Overtemperature Delta T protection, andprovides a backup to the High Neutron Flux trip. The setpoint includes corrections for changes in axialpower distribution, density and heat capacity of water with temperature, and dynamic compensation fortransport, thermowell, and RTD response time delays from the core to the RTD output indication.

Thesetpoint is automatically reduced according to the notations in Table 2.2-1 to account for adverse axialflux differences.

The f2(AI) trip reset term in the Overpower Delta T trip function precludes power distributions that causethe fuel melt limit to be exceeded during a limiting Condition II event. The negative and positive Al limitsat which the f2(AI) term begins to reduce the trip setpoint and the dependence of f2(AI) on THERMALPOWER are determined on a cycle-specific basis using approved methodology and are specified in theCOLR per Specification 6.9.1.14.

The Overpower Delta T trip provides protection to mitigate the consequences of various size steambreaks as reported in WCAP-9226, "Reactor Core Response to Excessive Secondary Steam Releases."

Delta-To, as used in the Overtemperature and Overpower AT trips, represents the 100 percent RTP valueas measured by the plant for each loop. This normalizes each loop's AT trips to the actual operating conditions existing at the time of measurement, thus forcing the trip to reflect the equivalent full powerconditions as assumed in the accident analyses.

These differences in RCS loop AT can be due toseveral factors, e.g., measured RCS loop flows greater than thermal design flow, and slightly asymmetric power distributions between quadrants.

While RCS loop flows are not expected to change with cycle life,radial power redistribution between quadrants may occur, resulting in small changes in loop specific ATvalues. Accurate determination of the loop specific AT value should be made quarterly and under steadystate conditions (i.e., power distributions not affected by xenon or other transient conditions.).

Pressurizer PressureThe Pressurizer High and Low Pressure trips are provided to limit the pressure range in which reactoroperation is permitted.

The High Pressure trip is backed up by the pressurizer code safety valves forRCS overpressure protection, and is therefore set lower than the set pressure for these valves (2485psig). The Low Pressure trip provides protection by tripping the reactor in the event of a loss of reactorcoolant pressure.

Pressurizer Water LevelThe Pressurizer High Water Level trip ensures protection against Reactor Coolant Systemoverpressurization by limiting the water level to a volume sufficient to retain a steam bubble and preventwater relief through the pressurizer safety valves. No credit was taken for operation of this trip in theaccident analyses;

however, its functional capability at the specified trip setting is required by thisspecification to enhance the overall reliability of the Reactor Protection System.October 10, 2012SEQUOYAH-UNIT 2 B 2-8 Amendment No. 132, 214 LIMITING SAFETY SYSTEM SETTINGSBASESLoss of FlowThe Loss of Flow trips provide core protection to prevent DNB in the event of a loss of one or morereactor coolant pumps.Above 11 percent of RATED THERMAL POWER, an automatic reactor trip will occur if the flow in any twoloops drops below 90 percent of nominal full loop flow. Above the P-8 interlock, automatic reactor trip willoccur if the flow in any single loop drops below 90 percent of nominal full loop flow. This latter trip willprevent the minimum value of the DNBR from going below 1.30 during normal operational transients andanticipated transients when 3 loops are in operation and the Overtemperature Delta T trip setpoint isadjusted to the value specified for all loops in operation.

Steam Generator Water LevelThe Steam Generator Water Level Low-Low trip protects the reactor from loss of heat sink in the event ofa sustained steam/feedwater flow mismatch resulting from loss of normal feedwater or a feedwater system pipe break, outside of containment.

This function also provides input to the steam generator levelcontrol system. IEEE 279 requirements are satisfied by 2/3 logic for protection function actuation, thusallowing for a single failure of a channel and still performing the protection function.

Control/protection interaction is addressed by the use of the Median Signal Selector which prevents a single failure of achannel providing input to the control system requiring protection function action. That is, a single failureof a channel providing input to the control system does not result in the control system initiating acondition requiring protection function action. The Median Signal Selector performs this by not selecting the channels indicating the highest or lowest steam generator levels as input to the control system.With the transmitters located inside containment and thus possibly experiencing adverse environmental conditions (due to a feedline break), the Environmental Allowance Modifier (EAM) was devised.

TheEAM function (Containment Pressure (EAM) with a setpoint of _< 0.5 psig) senses the presence ofadverse containment conditions (elevated pressure) and enables the Steam Generator Water Level -Low-Low trip setpoint (Adverse) which reflects the increased transmitter uncertainties due to thisenvironment.

The EAM allows the use of a lower Steam Generator Water Level -Low-Low (EAM) tripsetpoint when these conditions are not present, thus allowing more margin to trip for normal operating conditions.

The Trip Time Delay (TTD) creates additional operational margin when the plant needs it most, duringearly escalation to power, by allowing the operator time to recover level when the primary side load issufficiently small to allow such action. The TTD is based on continuous monitoring of primary side powerthrough the use of RCS loop AT. Two time delays are calculated, based on the number of steamgenerators indicating less than the Low-Low Level trip setpoint and the primary side power level. Themagnitude of the delays decreases with increasing October 10, 2012SEQUOYAH

-UNIT 2 B 2-9 Amendment Nos. 130, 132 LIMITING SAFETY SYSTEM SETTINGSBASESSteam Generator Water Level (Cont'd)primary side power level, up to 50 percent RTP. Above 50 percent RTP there are no time delays for theLow-Low level trips.In the event of failure of a Steam Generator Water Level channel, it is placed in the trip condition as inputto the Solid State Protection System and does not affect either the EAM or TTD setpoint calculations forthe remaining operable channels.

It is then necessary for the operator to force the use of the shorter TTDtime delay by adjustment of the single steam generator time delay calculation (Ts) to match the multiplesteam generator time delay calculation (TM) for the affected protection set, through the MMI. Failure ofthe Containment Pressure (EAM) channel to a protection set also does not affect the EAM setpointcalculations.

This results in the requirement that the operator adjust the affected Steam Generator WaterLevel -Low-Low (EAM) trip setpoints to the same value as the Steam Generator Water Level -Low-Low(Adverse).

Failure of the RCS loop AT channel input (failure of more than one TH RTD or failure of a TcRTD) does not affect the TTD calculation for a protection set. This results in the requirement that theoperator adjust the threshold power level for zero seconds time delay from 50 percent RTP to 0 percentRTP, through the MMI.The High Containment Pressure ESF trip that generates a safety injection signal and subsequent reactor trip protects the reactor from loss of heat sink in the event of a sustained steam/feedwater flowmismatch resulting from a feedwater system pipe break inside of containment.

IEEE 279 requirements are satisfied by 2/3 logic for protection function actuation, thus allowing for a single failure of a channeland still performing the protection function.

Undervoltape and Underfrequency

-Reactor Coolant Pump BussesThe Undervoltage and Underfrequency Reactor Coolant Pump bus trips provide reactor core protection against DNB as a result of loss of voltage or underfrequency to more than one reactor coolant pump. Thespecified setpoints assure a reactor trip signal is generated before the low flow trip setpoint is reached.Time delays are incorporated in the underfrequency and undervoltage trips to prevent spurious reactortrips from momentary electrical power transients.

For undervoltage, the delay is set so that the timerequired for a signal to reach the reactor trip breakers following the simultaneous trip of two or morereactor coolant pump bus circuit breakers shall not exceed 1.2 seconds.

For underfrequency, the delay isset so that the time required for a signal to reach the reactor trip breakers after the underfrequency tripsetpoint is reached shall not exceed 0.6 seconds.Turbine TripA Turbine Trip causes a direct reactor trip when operating above P-9. Each of the turbine trips provideturbine protection and reduce the severity of the ensuing transient.

No credit was taken in the accidentanalyses for operation of these trips. Their functional capability at the specified trip settings is required toenhance the overall reliability of the Reactor Protection System.October 10, 2012SEQUOYAH

-UNIT 2 B 2-10 Amendment No. 132 LIMITING SAFETY SYSTEM SETTINGSBASESSafety Iniection Input from ESFIf a reactor trip has not already been generated by the reactor protective instrumentation, the ESFautomatic actuation logic channels will initiate a reactor trip upon any signal which initiates a safetyinjection.

This trip is provided to protect the core in the event of a LOCA. The ESF instrumentation channels which initiate a safety injection signal are shown in Table 3.3-3.Reactor Trip System Interlocks The Reactor Trip System Interlocks perform the following functions on increasing power:P-6 Enables the manual block of the source range reactor trip (i.e.,prevents premature block of source range trip).P-7 Defeats the automatic block of reactor trip on: Low flow in moreP-13 than one primary coolant loop, reactor coolant pump undervoltage andunderfrequency, pressurizer low pressure, and pressurizer highlevel.P-8 Defeats the automatic block of reactor trip on low RCS coolant flowin a single loop.P-9 Defeats the automatic block of reactor trip on turbine trip.P-1 0 Enables the manual block of reactor trip on power range (lowsetpoint),

intermediate range, as a backup block for source range,and intermediate range rod stops (i.e., prevents premature block ofthe noted functions).

On decreasing power, the opposite function is performed at reset setpoints.

P-4 Reactor-tripped

-Actuates turbine trip, closes main feedwater valves on Tav, below setpoint, prevents the opening of the mainfeedwater valves which were closed by a safety injection or highsteam generator water level signal, allows manual block of theautomatic reactuation of safety injection.

Reactor not tripped -defeats manual block preventing automatic reactuation of safety injection.

October 10, 2012SEQUOYAH

-UNIT 2 B 2-11 Amendment No. 132 POWER DISTRIBUTION LIMITSBASES3/4.2.4 QUADRANT POWER TILT RATIOThe QUADRANT POWER TILT RATIO limit assures that no anomaly exists such that the radialpower distribution satisfies the design values used in the power capability analysis.

Radial powerdistribution measurements are made during startup testing and periodically during power operation.

The QUADRANT POWER TILT RATIO limit at which corrective action is required provides DNBand linear heat generation protection with x-y plane power tilts. The QUADRANT POWER TILT RATIOlimit is reflected by a corresponding peaking augmentation factor which is included in the generation ofthe AFD limits.The 2-hour time allowance for operation with the tilt condition greater than 1.02 but less than1.09, is provided to allow identification and correction of a dropped or misaligned control rod. In the eventsuch action does not correct the tilt, the margin for uncertainty on FQ(X,Y,Z) is reinstated by reducing theallowable THERMAL POWER by 3 percent for each percent of tilt in excess of 1.02.3/4.2.5 DNB PARAMETERS The limits on the DNB related parameters assure that each of the parameters are maintained within the normal steady state envelope of operation assumed in the transient and accident analyses.

The limits are consistent with the initial FSAR assumptions and have been analytically demonstrated adequate to maintain a minimum DNBR of greater than or equal to the safety analysis DNBR limitthroughout each analyzed transient.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months periodic surveillance of these parameters through instrument readout is sufficient toensure that the parameters are restored within their limits following load changes and other expectedtransient operation.

October 10, 2012SEQUOYAH

-UNIT 2 B 3/4 2-4 Amendment 21, 130, 146, 214, 324 INSTRUMENTATION BASESACCIDENT MONITORING INSTRUMENTATION (Continued)

Determine whether systems important to safety are performing their intended functions.

Provide information to the operators that will enable them to determine the likelihood of a grossbreach of the barriers to radioactivity release and to determine if a gross breach of a barrier hasoccurred.

For Sequoyah, the redundant channel capability for Auxiliary Feedwater (AFW) flow consists of asingle AFW flow channel for each Steam Generator with the second channel consisting of three AFWvalve position indicators (two level control valves for the motor driven AFW flowpath and one level controlvalve for the turbine drive AFW flowpath) for each steam generator.

March 5, 2013SEQUOYAH

-UNIT 2 B 3/4 3-3a Amendment Nos. 135, 149 RCS Leakage Detection Instrumentation B 3/4.4.6REACTOR COOLANT SYSTEMBASESAPPLICABLE SAFETYANALYSESThe steam generator tube rupture (SGTR) accident is the limiting designbasis event for SG tubes and avoiding an SGTR is the basis for thisspecification.

The analysis of an SGTR event assumes a boundingprimary to secondary leakage rate equal to the operational leakage ratelimits in LCO 3.4.6.2 "Operational Leakage,"

plus the leakage rateassociated with a double-ended rupture of a single tube. The accidentanalysis for a SGTR assumes the contaminated secondary fluid isreleased to the atmosphere via safety valves. The main condenser isolates based on an assumed concurrent loss of off-site power.The analysis for design basis accidents and transients other than a SGTRassume the SG tubes retain their structural integrity (i.e., they areassumed not to rupture).

In these analyses, the steam discharge to theatmosphere depends on the accident and whether there are faulted SGsassociated with the accident.

For a steamline break (SLB), the maximumprimary to secondary leakage under accident conditions is limited to 3.7gpm from the faulted SG and 0.1 gpm from each of the non-faulted SGs.For other accidents that assume a faulted SG (e.g., feedwater linebreak), the maximum primary to secondary leakage under accidentconditions is limited to 1.0 gpm from the faulted SG and 0.1 gpm fromeach of the non-faulted SGs. For accidents in which there are no faultedSGs, the primary to secondary leakage is limited to 0.1 gpm from eachSG. For accidents that do not involve fuel damage, the primary coolantactivity level of DOSE EQUIVALENT 1-131 is assumed to be equal to theLCO 3.4.8, "Specific Activity,"

limits. For accidents that assume fueldamage, the primary coolant activity is a function of the amount of activityreleased from the damaged fuel. The dose consequences of theseevents are within the limits of GDC 19 (Ref. 2), and 10 CFR 100 (Ref. 3).Steam generator tube integrity satisfies Criterion 2 of 10 CFR50.36(c)(2)(ii).

LCO The LCO requires that SG tube integrity be maintained.

The LCO alsorequires that all SG tubes that satisfy the repair criteria be plugged inaccordance with the Steam Generator Program.During an SG inspection, any inspected tube that satisfies the SteamGenerator Program repair criteria is removed from service by plugging.

Ifa tube was determined to satisfy the repair criteria but was not plugged,the tube may still have tube integrity.

SEQUOYAH

-UNIT 2B 3/4 4-3aOctober 5, 2012Amendment No. 181, 211, 213, 243,267, 291,305, 309, 318, 323 RCS Leakage Detection Instrumentation B 3/4.4.6REACTOR COOLANT SYSTEMBASESLCO (continued)

In the context of this specification, a SG tube is defined as the entirelength of the tube, including the tube wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet.The tube-to-tubesheet weld is not considered part of the tube.A SG tube has tube integrity when it satisfies the SG performance criteria.

The SG performance criteria are defined in Specification 6.8.4.k "SteamGenerator Program,"

and describe acceptable SG tube performance.

The Steam Generator Program also provides the evaluation process fordetermining conformance with the SG performance criteria.

There are three SG performance criteria:

structural integrity, accidentinduced leakage, and operational leakage.

Failure to meet any one ofthese criteria is considered failure to meet the LCO.The structural integrity performance criterion provides a margin of safetyagainst tube burst or collapse under normal and accident conditions, andensures structural integrity of the SG tubes under all anticipated transients included in the design specification.

Tube burst is defined as,"The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening areaincreased in response to constant pressure) accompanied by ductile(plastic) tearing of the tube material at the ends of the degradation.'

Tubecollapse is defined as, "For the load displacement curve for a givenstructure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero." The structural integrity performance criterion provides guidance on assessing loads thathave a significant effect on burst or collapse.

In that context, the term"significant" is defined as "An accident loading condition other thandifferential pressure is considered significant when the addition of suchloads in the assessment of the structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition tobe established."

For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. Forcircumferential degradation, the classification of axial thermal loads asprimary or secondary loads will be evaluated on a case-by-case basis.The division between primary and secondary classifications will be basedon detailed analysis and/or testing.October 5, 2012SEQUOYAH

-UNIT 2 B 3/4 4-3b Amendment No. 181, 211, 213, 243,267, 291,305 RCS Leakage Detection Instrumentation B 3/4.4.6REACTOR COOLANT SYSTEMBASESLCO (continued)

Structural integrity requires that the primary membrane stress intensity ina tube not exceed the yield strength for all American Society ofMechanical Engineers (ASME) Code,Section III, Service Level A (normaloperating conditions),

and Service Level B (upset or abnormal conditions) transients included in the design specification.

This includes safetyfactors and applicable design basis loads based on ASME Code, SectionIII, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).The accident induced leakage performance criterion ensures that theprimary to secondary leakage caused by a design basis accident, otherthan a SGTR, is within the accident analysis assumptions.

The accidentanalyses assumptions are discussed in the Applicable Safety Analysessection.

The accident induced leakage rate includes any primary tosecondary leakage existing prior to the accident in addition to primary tosecondary leakage induced during the accident.

The operational leakage performance criterion provides an observable indication of SG tube conditions during plant operation.

The limit onoperational leakage is contained in LCO 3.4.6.2, "Operational Leakage,"

and limits primary to secondary leakage through any one SG to 150gallons per day. This limit is based on the assumption that a single crackleaking this amount would not propagate to a SGTR under the stressconditions of a loss-of-coolant accident (LOCA) or a SLB. If this amountof leakage is due to more than one crack, the cracks are very small, andthe above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressuredifferential across the tubes is large. Large differential pressures acrossSG tubes can only be experienced in MODES 1, 2, 3, or 4.Reactor coolant system (RCS) conditions are far less challenging inMODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6,primary to secondary differential pressure is low, resulting in lowerstresses and reduced potential for leakage.October 5, 2012SEQUOYAH

-UNIT 2 B 3/4 4-3c Amendment No. 181, 211, 213, 243,267, 291,305, 323 RCS Leakage Detection Instrumentation B 3/4.4.6REACTOR COOLANT SYSTEMBASESACTIONS The ACTIONs are modified by a clarifying footnote that Action (a) may beentered independently for each SG tube. This is acceptable because theactions provide appropriate compensatory measures for each affected SGtube. Complying with the actions may allow for continued operation, andsubsequent affected SG tubes are governed by subsequent action entry,and application of associated actions.Actions (a) and (b)Action (a) applies if it is discovered that one or more SG tubes examined inan inservice inspection satisfy the tube repair criteria but were not pluggedin accordance with the Steam Generator Program as required by SR4.4.5.1.

An evaluation of SG tube integrity of the affected tube(s) must bemade. Steam generator tube integrity is based on meeting the SGperformance criteria described in the Steam Generator Program.

The SGrepair criteria define limits on SG tube degradation that allow for flawgrowth between inspections while still providing assurance that the SGperformance criteria will continue to be met. In order to determine if a SGtube that should have been plugged has tube integrity, an evaluation mustbe completed that demonstrates that the SG performance criteria willcontinue to be met until the next refueling outage or SG tube inspection.

The tube integrity determination is based on the estimated condition of thetube at the time the situation is discovered and the estimated growth of thedegradation prior to the next SG tube inspection.

If it is determined thattube integrity is not being maintained until the next refueling outage or SGinspection, Action (a) requires unit shutdown and Action (b) requires theaffected tube(s) be plugged.An allowed time of 7 days is sufficient to complete the evaluation whileminimizing the risk of plant operation with a SG tube that may not havetube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Action (a) allows plant operation to continue until the next refueling outageor SG inspection provided the inspection interval continues to besupported by an operational assessment that reflects the affected tubes.However, the affected tube(s) must be plugged prior to startup following the next refueling outage or SG inspection.

This allowed time isacceptable since operation until the next inspection is supported by theoperational assessment.

October 5, 2012SEQUOYAH

-UNIT 2 B 3/4 4-3d Amendment No. 181, 211, 213, 243,267, 291,305 RCS Leakage Detection Instrumentation B 3/4.4.6REACTOR COOLANT SYSTEMBASESACTIONS (continued)

If SG tube integrity is not being maintained, the reactor must be brought toHOT STANDBY within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and COLD SHUTDOWN within the next30 hours and the affected tube(s) plugged prior to restart (Mode 4).The action times are reasonable, based on operating experience, to reachthe desired plant condition from full power in an orderly manner andwithout challenging plant systems.SURVEILLANCE SR 4.4.5.0REQUIREMENTS During shutdown periods the SGs are inspected as required by this SRand the Steam Generator Program.

NEI 97-06, Steam Generator ProgramGuidelines (Ref. 1), and its referenced EPRI Guidelines, establish thecontent of the Steam Generator Program.

Use of the Steam Generator Program ensures that the inspection is appropriate and consistent withaccepted industry practices.

During SG inspections a condition monitoring assessment of the SG tubesis performed.

The condition monitoring assessment determines the "asfound" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been metfor the previous operating period.The Steam Generator Program determines the scope of the inspection andihe methods used to determine whether the tubes contain flaws satisfying the tube repair criteria.

Inspection scope (i.e., which tubes or areas oftubing within the SG are to be inspected) is a function of existing andpotential degradation locations.

The Steam Generator Program alsospecifies the inspection methods to be used to find potential degradation.

Inspection methods are a function of degradation morphology, nondestructive examination (NDE) technique capabilities, and inspection locations.

October 5, 2012SEQUOYAH

-UNIT 2 B 3/4 4-3e Amendment No. 181, 211, 213, 243,267, 291,305, 323 RCS Leakage Detection Instrumentation B 3/4.4.6REACTOR COOLANT SYSTEMBASESSURVEILLANCE REQUIREMENTS (continued)

The Steam Generator Program defines the frequency of SR 4.4.5.0.

Thefrequency is determined by the operational assessment and other limits inthe SG examination guidelines (Ref. 6). The Steam Generator Programuses information on existing degradations and growth rates to determine an inspection frequency that provides reasonable assurance that thetubing will meet the SG performance criteria at the next scheduled inspection.

In addition, Specification 6.8.4.k contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 4.4.5.1During an SG inspection, any inspected tube that satisfies the SteamGenerator Program repair criteria is removed from service by plugging.

The tube repair criteria delineated in Specification 6.8.4.k are intended toensure that tubes accepted for continued service satisfy the SGperformance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, inconjunction with other elements of the Steam Generator

Program, ensurethat the SG performance criteria will continue to be met until the nextinspection of the subject tube(s).

Reference 1 provides guidance forperforming operational assessments to verify that the tubes remaining inservice will continue to meet the SG performance criteria.

The frequency of this surveillance ensures that the surveillance has beencompleted and all tubes meeting the repair criteria are plugged prior tosubjecting the SG tubes to significant primary to secondary pressuredifferential (i.e., prior to HOT SHUTDOWN following a SG tube inspection).

October 5, 2012SEQUOYAH

-UNIT 2 B 3/4 4-3f Amendment No. 181, 211, 213, 243,267, 291,305 RCS Leakage Detection Instrumentation B 3/4.4.6REACTOR COOLANT SYSTEMBASESREFERENCES

1. NEI 97-06, "Steam Generator Program Guidelines."

2. 10 CFR 50 Appendix A, GDC 19.3. 10CFR100.

4. ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.5. Draft Regulatory Guide 1.121, "Basis for Plugging Degraded SteamGenerator Tubes," August 1976.6. EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines."

SEQUOYAH

-UNIT 2B 3/4 4-3gOctober 5, 2012Amendment No. 181, 211, 213, 243,267, 291,305, 323 RCS Leakage Detection Instrumentation B 3/4.4.6REACTOR COOLANT SYSTEMBASESPrimary to secondary leakage is a factor in the dose releases outsidecontainment resulting from a steam generator tube rupture or a steam line break(SLB) accident.

To a lesser extent, other accidents or transients also involvesecondary steam release to the atmosphere.

The leakage contaminates thesecondary fluid.The FSAR (Ref. 3) analysis for steam generator tube rupture (SGTR) assumesthe contaminated secondary fluid is released via safety valves for up to30 minutes.

Operator action is taken to isolate the affected steam generator within this time period. The 0.4 gpm operational primary to secondary leakagesafety analysis assumption is relatively inconsequential.

The SLB is more limiting for site radiation releases.

The safety analysis for theSLB accident assumes a 3.7 gpm primary to secondary leakage through theaffected generator and 0.3 gpm through the non-affected generators as an initialcondition.

The dose consequences resulting from the SLB accident are wellwithin the limits defined in 10 CFR 100 or the staff approved licensing basis (i.e.,a small fraction of these limits).

The expected leak rate following a steam linerupture is limited to below 3.7 gpm at atmospheric conditions and 70OF in thefaulted loop, which will limit the calculated offsite doses to within 10 percent ofthe 10 CFR 100 guidelines.

The RCS operational leakage satisfies Criterion 2 of the NRC Policy Statement.

LCO RCS operational leakage shall be limited to:a. PRESSURE BOUNDARY LEAKAGENo PRESSURE BOUNDARY LEAKAGE is allowed, being indicative ofmaterial deterioration.

Leakage of this type is unacceptable as the leakitself could cause further deterioration, resulting in higher leakage.Violation of this LCO could result in continued degradation of the RCPB.Leakage past seals and gaskets is not PRESSURE BOUNDARYLEAKAGE.b. UNIDENTIFIED LEAKAGEOne gpm of UNIDENTIFIED LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring andcontainment pocketOctober 5, 2012SEQUOYAH

-UNIT 2 B 3/4 4-4f Amendment No. 211, 213, 227, 250, 305, 323 ECCS -ShutdownB 3/4.5.3B 3/4.5 EMERGENCY CORE COOLING SYSTEM (ECCS)B 3/4.5.3 ECCS -ShutdownBASESBACKGROUND The Background section for Bases 3.5.2, "ECCS -Operating,"

isapplicable to these Bases, with the following modifications.

In MODE 4,the required ECCS train consists of two separate subsystems:

centrifugal charging (high head) and residual heat removal (RHR) (lowhead). For the RHR subsystem during the injection phase, water is takenfrom the refueling storage tank (RWST) and injected in the ReactorCoolant System (RCS) through at least two cold legs.The ECCS flow paths consist of piping, valves, heat exchangers, andpumps such that water from the refueling water storage tank (RWST) canbe injected into the Reactor Coolant System (RCS) following theaccidents described in Bases 3.5.2.APPLICABLE SAFETYANALYSESThe Applicable Safety Analyses section of Bases 3.5.2 also applies tothis Bases section.Due to the stable conditions associated with operation in MODE 4 and thereduced probability of occurrence of a Design Basis Accident (DBA), theECCS operational requirements are reduced.

It is understood in thesereductions that certain automatic safety injection (SI) actuation is notavailable.

In this MODE, sufficient time exists for manual actuation of therequired ECCS to mitigate the consequences of a DBA.Only one train of ECCS is required for MODE 4. This requirement dictates that single failures are not considered during this MODE ofoperation.

One train of ECCS during the injection phase provides sufficient flow forcore cooling, by the centrifugal charging subsystem supplying each of thefour cold legs and the RHR subsystem supplying at least two cold legs, tomeet the analysis requirements for a credible MODE 4 Loss of CoolantAccident (LOCA.)The ECCS trains satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCOIn MODE 4, one of the two independent (and redundant)

ECCS trains is required to be OPERABLE to ensure that sufficient ECCSflow is available to the core following a DBA.SEQUOYAH

-UNIT 2March 24, 2012BR35, BR38B 3/4 5-12 ECCS -ShutdownB 3/4.5.3BASESLCO (continued)

In MODE 4, an ECCS train consists of a centrifugal charging subsystem and an RHR subsystem.

Each train includes the piping, instruments, andcontrols to ensure an OPERABLE flow path capable of taking suctionfrom the RWST and transferring suction to the containment sump.During an event requiring ECCS actuation, a flow path is required toprovide an abundant supply of water from the RWST to the RCS via theECCS pumps and their respective supply headers to the coldleg injection nozzles.

In the long term, this flow path may be switched totake its supply from the containment sump and to deliver its flow to theRCS hot and cold legs.Either RHR cold leg injection valve FCV-63-93 or FCV-63-94 may beclosed when in MODE 4, for testing of the primary/secondary checkvalves in the injection lines. Closing one of the two cold leg injection flowpaths does not make ECCS RHR subsystem inoperable.

This LCO is modified by a Note that allows an RHR train to be considered OPERABLE during alignment and operation for .decay heat removal, ifcapable of being manually realigned (remote or local) to the ECCS modeof operation and not otherwise inoperable.

The manual actionsnecessary to realign the RHR subsystem may include actions to cool theRHR system piping due to the potential for steam voiding in piping or forinadequate NPSH available at the RHR pumps. This allows operation inthe RHR mode during MODE 4.APPLICABILITY In MODES 1, 2, and 3, the OPERABILITY requirements for ECCS arecovered by LCO 3.5.2.In MODE 4 with RCS temperature below 3500F, one OPERABLE ECCStrain is acceptable without single failure consideration, on the basis of thestable reactivity of the reactor and the limited core cooling requirements.

In MODES 5 and 6, plant conditions are such that the probability of anevent requiring ECCS injection is extremely low. Core coolingrequirements in MODE 5 are addressed by LCO 3.4.1.4, "ReactorCoolant System Cold Shutdown."

MODE 6 core cooling requirements areaddressed by LCO 3.9.8.1 "Residual Heat Removal and CoolantCirculation

-All Water Levels,"

and LCO 3.9.8.2 "Residual Heat Removaland Coolant Circulation

-Low Water Level."March 24, 2012SEQUOYAH

-UNIT 2 B 3/4 5-13 BR35, BR36, BR38 ECCS -ShutdownB 3/4.5.3BASESACTIONS A Note prohibits the application of LCO 3.0.4b to an inoperable ECCShigh head subsystem when entering MODE 4. There is an increased riskassociated with entering MODE 4 from MODE 5 with an inoperable ECCShigh head subsystem and the provisions of LCO 3.0.4b, which allow entryinto a MODE or other specified condition in the Applicability with the LCOnot met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

A second Note allows the required ECCS RHR subsystem to beinoperable because of surveillance testing of RCS pressure isolation valve leakage (FCV-74-1 and FCV-74-2).

This allows testing while RCSpressure is high enough to obtain valid leakage data and following valveclosure for RHR decay heat removal path. The condition requiring alternate heat removal methods ensures that the RCS heatup rate can becontrolled to prevent MODE 3 entry and thereby ensure that the reducedECCS operational requirements are maintained.

The condition requiring manual realignment capability, FCV-74-1 and FCV-74-2 can be openedfrom the main control room ensures that in the unlikely event of a designbasis accident during the one hour of surveillance

testing, the RHRsubsystem can be placed in ECCS recirculation mode when required tomitigate the event.Action a.With no ECCS RHR subsystem

OPERABLE, the plant is not prepared torespond to a loss of coolant accident or to continue a cooldown using theRHR pumps and heat exchangers.

The action time of immediately toinitiate actions that would restore at least one ECCS RHR subsystem toOPERABLE status ensures that prompt action is taken to restore therequired cooling capacity.

Normally, in MODE 4, reactor decay heat isremoved from the RCS by an RHR loop. If no RHR loop is OPERABLEfor this function, reactor decay heat must be removed by some alternate method, such as use of the steam generators.

The alternate means ofheat removal must continue until the inoperable RHR loop components can be restored to operation so that decay heat removal is continuous.

With both RHR pumps and heat exchangers inoperable, it would beunwise to require the plant to go to MODE 5, where the only available heat removal system is the RHR. Therefore, the appropriate action is toinitiate measures to restore one ECCS RHR subsystem and to continuethe actions until the subsystem is restored to OPERABLE status.March 24, 2012SEQUOYAH

-UNIT 2 B 3/4 5-14 BR35 ECCS -ShutdownB 3/4.5.3BASESACTIONS (continued)

Action b.With no ECCS high head subsystem

OPERABLE, due to the inoperability of the centrifugal charging pump or flow path from the RWST, the plant isnot prepared to provide high pressure response to Design Basis Eventsrequiring SI. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months action time to restore at least one ECCS highhead subsystem to OPERABLE status ensures that prompt action istaken to provide the required cooling capacity or to initiate actions toplace the plant in MODE 5, where an ECCS train is not required.

When Action b cannot be completed within the required action time,within one hour, a controlled shutdown should be initiated.

Twenty fourhours is a reasonable time, based on operating experience, to reachMODE 5 in an orderly manner and without challenging plant systems oroperators.

SURVEILLANCE SR 4.5.3REQUIREMENTS The applicable Surveillance descriptions from Bases 3.5.2 apply.REFERENCES

1. The applicable references from Bases 3.5.2 apply.2. NRC Safety Evaluation Report, NUREG-001 1, Section 1.1,"Introduction,"

regarding Amendment 49 dated January 6, 1978.March 24, 2012BR35, BR38SEQUOYAH

-UNIT 2B 3/4 5-15 EMERGENCY CORE COOLING SYSTEMSBASES3/4.5.4 BORON INJECTION SYSTEMThis Specification was deleted.3/4.5.5 REFUELING WATER STORAGE TANKThe OPERABILITY of the refueling water storage tank (RWST), as part of theECCS, ensures that a sufficient supply of borated water is available for injection by theECCS in the event of a LOCA. The limits on RWST minimum volume and boronconcentration ensure that 1) sufficient water is available within containment to permitrecirculation-cooling flow to the core, and 2) the reactor will remain subcritical in the coldcondition following mixing of the RWST and the RCS water volumes with all control rodsinserted except for the most reactive control assembly.

These assumptions areconsistent with the LOCA analyses.

Additionally, the OPERABILITY of the RWST, aspart of the ECCS, ensures that sufficient negative reactivity is injected into the core tocounteract any positive increase in reactivity caused by RCS cooldown.

The contained water volume limit includes an allowance for water not usablebecause of tank discharge line location or other physical characteristics.

The limits on contained water volume and boron concentration of the RWST alsoensure a pH value of between 7.5 and 9.5 for the solution recirculated withincontainment after a LOCA. This pH band minimizes the evolution of iodine andminimizes the effect of chloride and caustic stress corrosion on mechanical systems andcomponents.

March 24, 2012SEQUOYAH

-UNIT 2 B 3/4 5-16 Amendment No. 131, 288, 290 EMERGENCY CORE COOLING SYSTEMBASES3/4.5.6 SEAL INJECTION FLOWBACKGROUND The function of the seal injection throttle valves during an accidentis similar to the function of the ECCS throttle valves in that eachrestricts flow from the centrifugal charging pump header to theReactor Coolant System (RCS).The restriction on reactor coolant pump (RCP) seal injection flowlimits the amount of ECCS flow that would be diverted from theinjection path following an accident.

This limit is based on safetyanalysis assumptions that are required because RCP sealinjection flow is not isolated during safety injection.

APPLICABLE SAFETY ANALYSESAll ECCS subsystems are taken credit for in the large break lossof coolant accident (LOCA) at full power (Ref. 1). The LOCAanalysis establishes the minimum flow for the ECCS pumps. Thecentrifugal charging pumps are also credited in the small breakLOCA analysis.

This analysis establishes the flow and discharge head at the design point for the centrifugal charging pumps. Thesteam generator tube rupture and main steam line break eventanalyses also credit the centrifugal charging pumps, but are notlimiting in their design. Reference to these analyses is made inassessing changes to the Seal Injection System for evaluation oftheir effects in relation to the acceptance limits in these analyses.

This LCO ensures that seal injection flow will be sufficient for RCPseal integrity but limited so that the ECCS trains will be capable ofdelivering sufficient water to match boiloff rates soon enough tominimize uncovering of the core following a large LOCA. It alsoensures that the centrifugal charging pumps will deliver sufficient water for a small LOCA and sufficient boron to maintain the coresubcritical.

For smaller LOCAs, the charging pumps alone deliversufficient fluid to overcome the loss and maintain RCS inventory.

Seal injection flow satisfies Criterion 2 of the NRC PolicyStatement.

SEQUOYAH

-UNIT 2B 3/4 5-17March 24, 2012Amendment No. 131, 250 EMERGENCY CORE COOLING SYSTEMBASESLCOThe intent of the LCO limit on seal injection flow is to make surethat flow through the RCP seal water injection line is low enoughto ensure that sufficient centrifugal charging pump injection flow isdirected to the RCS via the injection points (Ref. 2).The LCO is not strictly a flow limit, but rather a flow limit based ona flow line resistance.

In order to establish the proper flow lineresistance, a pressure and flow must be known. The flow lineresistance is established by adjusting the RCP seal injection needle valves to provide a total seal injection flow in theacceptable region of Technical Specification Figure 3.5.6-1.

Thecentrifugal charging pump discharge header pressure remainsessentially constant through all the applicable MODES of thisLCO. A reduction in RCS pressure would result in more flowbeing diverted to the RCP seal injection line than at normaloperating pressure.

The valve settings established at theprescribed centrifugal charging pump discharge header pressureresult in a conservative valve position should RCS pressuredecrease.

The flow limits established by Technical Specification Figure 3.5.6-1 are consistent with the accident analysis.

The limits on seal injection flow must be met to render the ECCSOPERABLE.

If these conditions are not met, the ECCS flow willnot be as assumed in the accident analyses.

APPLICABILITY In MODES. 1, 2, and 3, the seal injection flow limit is dictated byECCS flow requirements, which are specified for MODES 1, 2, 3,and 4. The seal injection flow limit is not applicable for MODE 4and lower, however, because high seal injection flow is lesscritical as a result of the lower initial RCS pressure and decay heatremoval requirements in these MODES. Therefore, RCP sealinjection flow must be limited in MODES 1, 2, and 3 to ensureadequate ECCS performance.

March 24, 2012Amendment No. 250SEQUOYAH

-UNIT 2B 3/4 5-18 EMERGENCY CORE COOLING SYSTEMBASESACTION With the seal injection flow exceeding its limit, the amount ofcharging flow available to the RCS may be reduced.

Under thiscondition, action must be taken to restore the flow to below itslimit. The operator has 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months from the time the flow is known tobe above the limit to correctly position the manual valves and thusbe in compliance with the accident analysis.

The completion timeminimizes the potential exposure of the plant to a LOCA withinsufficient injection flow and provides a reasonable time torestore seal injection flow within limits. This time is conservative with respect to the completion times of other ECCS LCOs; it isbased on operating experience and is sufficient for takingcorrective actions by operations personnel.

When the actions cannot be completed within the requiredcompletion time, a controlled shutdown must be initiated.

Thecompletion time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months for reaching MODE 3 from MODE 1 isa reasonable time for a controlled

shutdown, based on operating experience and normal cooldown rates, and does not challenge plant safety systems or operators.

Continuing the plant shutdownfrom MODE 3, an additional 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is a reasonable time, basedon operating experience and normal cooldown rates, to reachMODE 4, where this LCO is no longer applicable.

SURVEILLANCE Surveillance 4.5.6REQUIREMENTS Verification every 31 days that the manual seal injection throttlevalves are adjusted to give a flow within the limit ensures thatproper manual seal injection throttle valve position, and hence,proper seal injection flow, is maintained.

The differential pressurethat is abode the reference minimum value is established betweenthe charging header (PT 62-92) and the RCS, and total sealinjection flow is verified to be within the limits determined inaccordance with the ECCS safety analysis (Ref. 3). The sealwater injection flow limits are shown in Technical Specification Figure 3.5.6-1.

The frequency of 31 days is based on engineering judgment and is consistent with other ECCS valve surveillance frequencies.

The frequency has proven to be acceptable throughoperating experience.

The requirements for charging flow vary widely according to plantstatus and configuration.

When charging flow is adjusted, thepositions of the air-operated valves, which control charging flow,March 24, 2012SEQUOYAH

-UNIT 2 B 3/4 5-19 Amendment No. 250 EMERGENCY CORE COOLING SYSTEMBASESare adjusted to balance the flows through the charging header andthrough the seal injection header to ensure that the seal injection flow to the RCPs is maintained between 8 and 13 gpm per pump.The reference minimum differential pressure across the sealinjection needle valves ensures that regardless of the variedsettings of the charging flow control valves that are required tosupport optimum charging flow, a reference test condition can beestablished to ensure that flows across the needle valves arewithin the safety analysis.

The values in the safety analysis forthis reference set of conditions are calculated based on conditions during power operation and they are correlated to the minimumECCS flow to be maintained under the most limiting accidentconditions.

As noted, the surveillance is not required to be performed until 4hours after the RCS pressure has stabilized within a +/- 20 psigrange of normal operating pressure.

The RCS pressurerequirement is specified since this configuration will produce therequired pressure conditions necessary to assure that the manualvalves are set correctly.

The exception is limited to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months toensure that the surveillance is timely. Performance of thissurveillance within the 4-hour allowance is required to maintaincompliance with the provisions of Specification 4.0.3.REFERENCES

1. FSAR, Chapter 6.3 "Emergency Core Cooling System" andChapter 15.0 "Accident Analysis."

2. 10 CFR 50.46.3. Westinghouse Electric Company Calculation CN-FSE-99-48 March 24, 2012Amendment No. 250SEQUOYAH

-UNIT 2B 3/4 5-20 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 AND 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMSThe OPERABILITY of the A.C. and D.C power sources and associated distribution systems duringoperation ensures that sufficient power will be available to supply the safety related equipment required for1) the safe shutdown of the facility and 2) the mitigation and control of accident conditions within thefacility.

The minimum specified independent and redundant A.C. and D.C. power sources and distribution systems satisfy the requirements of General Design Criterion 17 of Appendix "A" to 10 CFR 50.The electrically powered AC safety loads are separated into redundant load groups such that lossof any one load group will not prevent the minimum safety functions from being performed.

Specification 3.8.1.1 requires two physically independent circuits between the offsite transmission network and theonsite Class 1 E Distribution System and four separate and independent diesel generator sets to beOPERABLE in MODES 1, 2, 3, and 4. These requirements ensure availability of the required power toshut down the reactor and maintain it in a safe shutdown condition after an abnormal operational transient or a postulated design basis accident.

Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident.

Minimum required switchyard voltages are determined by evaluation of plant accident loading and the associated voltage drops between the transmission network and theseloads. These minimum voltage values are provided to TVA's Transmission Operations for use in systemstudies to support operation of the transmission network in a manner that will maintain the necessary voltages.

Transmission Operations is required to notify SQN Operations if it is determined that thetransmission network may not be able to support accident loading or shutdown operations as required by10 CFR 50, Appendix A, GDC-17. Any offsite power circuits supplied by that transmission network thatare not able to support accident loading or shutdown operations are inoperable.

The unit station service transformers (USSTs) utilize auto load tap changers to provide therequired voltage response for accident loading.

The load tap changer associated with a USST is requiredto be functional and in "automatic" for the USST to supply power to a 6.9 kV Unit Board.The inability to supply offsite power to a 6.9 kV Shutdown Board constitutes the failure of only oneoffsite circuit, as long as offsite power is available to the other load group's Shutdown Boards. Thus, ifone or both 6.9 kV Shutdown Boards in a load group do not have an offsite circuit available, then only oneoffsite circuit would be inoperable.

If one or more Shutdown Boards in each load group, or all fourShutdown Boards, do not have an offsite circuit available, then both offsite circuits would be inoperable.

An "available" offsite circuit meets the requirements of GDC-1 7, and is either connected to the 6.9 kVShutdown Boards or can be connected to the 6.9 kV Shutdown Boards within a few seconds.An offsite circuit consists of all breakers, transformers,

switches, interrupting

devices, cabling,and controls required to transmit power from the offsite transmission network (beginning at theswitchyard) to one load group of Class 1 E 6.9 kV Shutdown Boards (ending at the supply side of thenormal or alternate supply circuit breaker).

Each required offsite circuit is that combination of powersources described below that are normally connected to the Class 1 E distribution system, or can beconnected to the Class 1 E distribution system through automatic transfer at the 6.9 kV Unit Boards.The following offsite power configurations meet the requirements of LCO 3.8.1.1.a:

(Note that common station service transformer (CSST) B is a spare transformer with two sets ofsecondary windings that can be used to supply a total of two Start Buses for CSST A and/or CSST C,with each supplied Start Bus on a separate CSST B secondary winding.)

December 21, 2012SEQUOYAH

-UNIT 2 B 3/4 8-1 Amendment No. 123, 164, 195, 231,272, 325 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

1. Two offsite circuits consisting of a AND b (no board transfers required; a loss of either circuit will notprevent the minimum safety functions from being performed):

a. From the 161 kV transmission

network, through CSST A (winding X) to Start Bus 1A to 6.9 kVShutdown Board 1B-B (through 6.9 kV Unit Board lC), and CSST A (winding Y) to Start Bus2A to 6.9 kV Shutdown Board 2B-B (through 6.9 kV Unit Board 2C); ANDb. From the 161 kV transmission

network, through CSST C (winding X) to Start Bus 2B to 6.9 kVShutdown Board 2A-A (through 6.9 kV Unit Board 2B), and CSST C (winding Y) to Start Bus1B to 6.9 kV Shutdown Board 1A-A (through 6.9 kV Unit Board 1B).2. Two offsite circuits consisting of a AND b (relies on automatic transfer from alignment a.1) to b.2)(b),or a.2) to b.1)(a) on a loss of (USSTs) 1A and 1B, OR relies on automatic transfer from alignment a.3)to b.2)(a),

or a.4) to b. 1)(b) on a loss of USSTs 2A and 2B):a. Normal power source alignments

1) From the 500 kV switchyard through USST 1A to 6.9 kV Shutdown Board 1A-A (through6.9 kV Unit Board 1B);2) From the 500 kV switchyard through USST 1 B to 6.9 kV Shutdown Board 1 B-B (through6.9 kV Unit Board lC);3) From the 161 kV switchyard through USST 2A to 6.9 kV Shutdown Board 2A-A (through6.9 kV Unit Board 2B); AND4) From the 161 kV switchyard through USST 2B to 6.9 kV Shutdown Board 2B-B (through6.9 kV Unit Board 2C).b. Alternate power source alignments

1) From the 161 kV transmission

network, through:(a) CSST A (winding X) to Start Bus 1A to 6.9 kV Shutdown Board 1B-B (through 6.9 kVUnit Board 1C); AND(b) CSST A (winding Y) to Start Bus 2A to 6.9 kV Shutdown Board 2B-B (through 6.9 kVUnit Board 2C); OR2) From the 161 kV transmission

network, through:(a) CSST C (winding X) to Start Bus 2B to 6.9 kV Shutdown Board 2A-A (through 6.9 kVUnit Board 2B), AND(b) CSST C (winding Y) to Start Bus 1B to 6.9 kV Shutdown Board 1A-A (through 6.9 kVUnit Board 1B).December 21, 2012SEQUOYAH

-UNIT 2 B 3/4 8-2 Amendment No. 123, 164, 195, 224,231,274, 290, 325 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

3. Two offsite circuits consisting of a AND b (relies on automatic transfer from alignment

a. 1) to b. 1)and b.2) on a loss of the Unit 2 USSTs; a loss of alignment a.2) or a.3) will not prevent the minimumsafety functions from being performed):

a. Normal power source alignments

1) From the 161 kV switchyard through USST 2A to 6.9 kV Shutdown Board 2A-A (through6.9 kV Unit Board 2B), and USST 2B to 6.9 kV Shutdown Board 2B-B (through 6.9 kVUnit Board 2C);2) From the 161 kV transmission

network, through CSST A (winding X) to Start Bus 1A to6.9 kV Shutdown Board 1 B-B (through 6.9 kV Unit Board 1 C); AND3) From the 161 kV transmission

network, through CSST C (winding Y) to Start Bus 1B to6.9 kV Shutdown Board 1A-A (through 6.9 kV Unit Board 1B).b. Alternate power. source alignments

1) From the 161 kV transmission

network, through CSST A (winding Y) to Start Bus 2A to6.9 kV Shutdown Board 2B-B (through 6.9 kV Unit Board 2C); AND2) From the 161 kV transmission

network, through CSST C (winding X) to Start Bus 2B to6.9 kV Shutdown Board 2A-A (through 6.9 kV Unit Board 2B).4. Two offsite circuits consisting of a AND b (relies on automatic transfer from alignment a.1) to b. 1)and b.2) on a loss of the Unit 1 USSTs; a loss of alignment a.2) or a.3) will not prevent the minimumsafety functions from being performed):

a. Normal power source alignments

1) From the 500 kV switchyard through USST 1A to 6.9 kV Shutdown Board 1A-A (through6.9 kV Unit Board 1 B), and USST 1 B to 6.9 kV Shutdown Board 1 B-B (through 6.9 kVUnit Board 1C);2) From the 161 kV transmission

network, through CSST A (winding Y) to Start Bus 2A to6.9 kV Shutdown Board 2B-B (through 6.9 kV Unit Board 2C); AND3) From the 161 kV transmission

network, through CSST C (winding X) to Start Bus 2B to6.9 kV Shutdown Board 2A-A (through 6.9 kV Unit Board 2B).b. Alternate power source alignments

1) From the 161 kV transmission

network, through CSST A (winding X) to Start Bus 1A to6.9 kV Shutdown Board 1 B-B (through 6.9 kV Unit Board lC); AND2) From the 161 kV transmission

network, through CSST C (winding Y) to Start Bus 1 B to6.9 kV Shutdown Board 1A-A (through 6.9 kV Unit Board 1B).December 21, 2012SEQUOYAH

-UNIT 2 B 3/4 8-3 Amendment No 123, 164, 195,224, 274, 325 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

Other offsite configurations are possible using different combinations of available USSTs andCSSTs, as long as the alignments are consistent with the analyzed configurations, and the alignments otherwise comply with the requirements of GDC 17.For example, to support breaker testing, offsite power to the 6.9 kV Shutdown Boards can berealigned from normal feed to alternate feed. This would result in Shutdown Boards 1A-A and 2A-A beingfed from Unit Boards 1A and 2A, respectively, and Shutdown Boards 1B-B and 2B-B being fed from UnitBoards 1D and 2D, respectively.

The CSST being utilized as the alternate power source to one loadgroup of Shutdown Boards would also be realigned (normally CSST A available to Shutdown Boards1 B-B and 2B-B or CSST C available to Shutdown Boards 1A-A and 2A-A, would be realigned to CSST Aavailable to Shutdown Boards 1A-A and 2A-A or CSST C available to Shutdown Boards 1 B-B and 2B-B).LCO 3.8.1.1 is modified by Note @ that specifies CSST A and CSST C are required to beavailable via automatic transfer at the associated 6.9 KV Unit Boards, when USST 2A and USST 2B arebeing utilized as normal power sources to the offsite circuits.

(Note that CSST B can be substituted forCSST A or CSST C.) This offsite power alignment is consistent with Configuration 3, as stated above.Note @ remains in effect until November 30, 2013, or until the USST modifications are implemented onUnits 1 and 2, whichever occurs first. (The scheduled startup from the Unit 1 fall 2013 refueling outage isNovember 2013.) Following expiration of Note @, Configuration 3 can continue to be used.The ACTION requirements specified for the levels of degradation of the power sources providerestriction upon continued facility operation commensurate with the level of degradation.

TheOPERABILITY of the power sources are consistent with the initial condition assumptions of the safetyanalyses and are based upon maintaining at least one redundant set of onsite A.C. and D.C. powersources and associated distribution systems OPERABLE during accident conditions coincident with anassumed loss of offsite power and single failure of the other onsite A.C. source.The footnote for Action b of LCO 3.8.1.1 requires completion of a determination that theOPERABLE diesel generators are not inoperable due to common cause failure or performance ofSurveillance 4.8.1.1.2.a.4 if Action b is entered.

The intent is that all diesel generator inoperabilities mustbe investigated for common cause failures regardless of how long the diesel generator inoperability persists.

Action b of LCO 3.8.1.1 is further modified by a second note which precludes making more thanone diesel generator inoperable on a pre-planned basis for maintenance, modifications, or surveillance testing.

The intent of this footnote is to explicitly exclude the flexibility of removing a diesel generator setfrom service as a part of a pre-planned activity.

While the removal of a diesel generator set (A or B train)is consistent with the initial condition assumptions of the accident

analysis, this configuration is judged asimprudent.

The term pre-planned is to be taken in the context of those activities which are routinely scheduled and is not relative to conditions which arise as a result of emergent or unforeseen events. Asan example, this footnote is not intended to preclude the actions necessary to perform the common modetesting requirements required by Action b. As another example, this footnote is not intended to preventthe required surveillance testing of the diesel generators should one diesel generator maintenance beunexpectedly extended and a second diesel generator fall within its required testing frequency.

Thus,application of the note is intended for pre-planned activities.

December 21, 2012SEQUOYAH

-UNIT 2 B 3/4 8-4 Amendment No. 123, 164, 195, 231,272, 325 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

In addition, this footnote is intended to apply only to those actions taken directly on the dieselgenerator.

For those actions taken relative to common support systems (e.g. ERCW), the supportfunction must be evaluated for impact on the diesel generator.

The action to determine that the OPERABLE diesel generators are not inoperable due to commoncause failures provides an allowance to avoid unnecessary testing of OPERABLE diesel generators.

If itcan be determined that the cause of the inoperable diesel generator does not exist on the OPERABLEdiesel generators, Surveillance Requirement 4.8.1.1.2.a.4 does not have to be performed.

If the cause ofinoperability exists on other diesel generator(s),

the other diesel generator(s) would be declaredinoperable upon discovery and Action e of LCO 3.8.1.1 would be entered as applicable.

Once thecommon failure is repaired, the common cause no longer exists, and the action to determine inoperability due to common cause failure is satisfied.

If the cause of the initial inoperable diesel generator cannot beconfirmed not to exist on the remaining diesel generators, performance of Surveillance 4.8.1.1.2.a.4 suffices to provide assurance of continued OPERABILITY of the other diesel generators.

According to Generic Letter 84-15, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable to confirm that the OPERABLE dieselgenerators are not affected by the same problem as the inoperable diesel generator.

Action f prohibits the application of LCO 3.0.4.b to an inoperable diesel generator.

There is anincreased risk associated with entering a MODE or other specified condition in the Applicability with aninoperable diesel generator and the provisions of LCO 3.0.4.b, which allow entry into a MODE or otherspecified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

The OPERABILITY of the minimum specified A.C. and D.C. power sources and associated distribution systems during shutdown and refueling ensures that 1) the facility can be maintained in theshutdown or refueling condition for extended time periods and 2) sufficient instrumentation and controlcapability is available for monitoring and maintaining the unit status.With the minimum required AC power sources not available, it is required to suspend COREALTERATIONS and operations involving positive reactivity additions that could result in loss of requiredSDM (Mode 5) or boron concentration (Mode 6). Suspending positive reactivity additions that could resultin failure to meet minimum SDM or boron concentration limit is required to assure continued safeoperation.

Introduction of coolant inventory must be from sources that have a boron concentration greaterthan or equal to that required in the RCS for minimum SDM or refueling boron concentration.

This mayresult in an overall reduction in RCS boron concentration but provides acceptable margin to maintaining subcritical operation.

Introduction of temperature changes including temperature increases whenoperating with a positive MTC must also be evaluated to ensure they do not result in a loss of requiredSDM.The requirements of Specification 3.8.2.1 provide those actions to be taken for the inoperability ofA.C. Distribution Systems.

Action a of this specification provides an 8-hour action for the inoperability ofone or more A.C. boards. Action b of this specification provides a relaxation of the 8-hour action to24-hours provided the Vital Instrument Power Board is inoperable solely as a result of one inoperable inverter and the board has been energized within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In this condition the requirements of Action ado not have to be applied.

Action b is not intended to provide actions for inoperable inverters, which isaddressed by the operability requirements for the boards, and is included only for relief from the 8-hourDecember 21, 2012SEQUOYAH

-UNIT 2 B 3/4 8-5 Amendment No.123, 164, 195,224, 231,274, 290 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued) action of Action a when only one inverter is affected.

More than one inverter inoperable will result in theinoperability of the associated 120 Volt A.C. Vital Instrument Power Board(s) in accordance with Action a.With more than one inverter inoperable entry into the actions of TS 3.0.3 is not applicable because Actiona includes provisions for multiple inoperable inverters as attendant equipment to the boards.The Surveillance Requirements for demonstrating the OPERABILITY of the diesel generators are inaccordance with the recommendations of Regulatory Guides 1.9 "Selection of Diesel Generator SetCapacity for Standby Power Supplies",

March 10, 1971, 1.108 "Periodic Testing of Diesel Generator UnitsUsed as Onsite Electric Power Systems at Nuclear Power Plants,"

Revision 1, August 1977, and 1.137"Fuel-Oil Systems for Standby Diesel Generators,"

Revision 1, October 1979. The surveillance requirements for the diesel generator load-run test and the 24-hour endurance and margin test are inaccordance with Regulatory Guide 1.9, Revision 3, July 1993, "Selection, Design, Qualification, andTesting of Emergency Diesel Generator Units Used as Class 1 E Onsite Electric Power Systems atNuclear Power Plant." During the diesel generator endurance and margin surveillance test, momentary transients outside the kw and kvar load ranges do not invalidate the test results.

Similarly, during thediesel generator load-run test, momentary transients outside the kw load range do not invalidate the testresults.Where the SRs discussed herein specify voltage and frequency tolerances, the following isapplicable.

6800 volts is the minimum steady state output voltage and the 10 second transient value.6800 volts is 98.6% of nominal bus voltage of 6900 volts and is based on the minimum voltage requiredfor the diesel generator supply breaker to close on the 6.9 kV Shutdown Board. The specified maximumsteady state output voltage of 7260 volts is based on the degraded over voltage relay setpoint and isequivalent to 110% of the nameplate rating of the 6600 volt motors. The specified minimum andmaximum frequencies of the diesel generator are 58.8 Hz and 61.2 Hz, respectively.

These values areequal to +/- 2% of the 60 Hz nominal frequency and are derived from the recommendations given inregulatory Guide 1.9.Where the SRs discuss maximum transient voltages during load rejection

testing, the following isapplicable.

The maximum transient voltage of 8880 volts represents a conservative limit to ensure theresulting voltage will not exceed a level that will cause component damage. It is based on themanufacturer's recommended high potential test voltage of 60% of the original factory high potential testvoltage (14.8 kV). The diesel generator manufacturer has determined that the engine and/or generator controls would not experience detrimental effects for transient voltages

< 9000 volts. The maximumtransient voltage of 8276 volts is retained from the original technical specifications to ensure that thevoltage transient following rejection of the single largest load is within the limits originally considered acceptable.

It was based on 114% of 7260 volts, which is the Range B service voltage per ANSI-C84.1.

The Surveillance Requirement (SR) to transfer the power supply to each 6.9 kV Unit Board fromthe normal supply to the alternate supply demonstrates the OPERABILITY of the alternate supply topower the shutdown loads. The 18 month Frequency of the Surveillance is based on engineering

judgment, taking into consideration the unit conditions required to perform the Surveillance, and isintended to be consistent with expected fuel cycle lengths.

Operating experience has shown that thesecomponents usually pass the SR when performed at the 18 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by two Notes. Thereason for Note # is that, during operation with the reactor critical, performance of this SR for the Unit 2December 21, 2012SEQUOYAH

-UNIT 2 B 3/4 8-6 Amendment No. 123, 164, 195,224, 231,274, 290, 325 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

Unit Boards could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, unit safety systems.

Note ## specifies that transfercapability is only required to be met for 6.9 kV Unit Boards that require normal and alternate powersupplies.

When both load groups are being supplied power by the USSTs, only the 6.9 kV Unit Boardsassociated with one load group are required to have normal and alternate power supplies.

Therefore, only one CSST is required to be OPERABLE and available as an alternate power supply. Additionally, manual transfers between the normal supply and the alternate supply are not relied upon to meet theaccident analysis.

Manual transfer capability is verified to ensure the availability of a backup to theautomatic transfer feature.The Surveillance Requirement for demonstrating the OPERABILITY of the Station batteries are based onthe recommendations of Regulatory Guide 1.129 "Maintenance Testing and Replacement of Large LeadStorage Batteries for Nuclear Power Plants,"

February 1978, and IEEE Std 450-1980, "IEEERecommended Practice for Maintenance, Testing and Replacement of Large Lead Storage Batteries forGenerating Stations and Substations."

Verifying average electrolyte temperature above the minimum for which the battery was sized,total battery terminal voltage onfloat charge, connection resistance values and the performance of batteryservice and discharge tests ensures the effectiveness of the charging system, the ability to handle highdischarge rates and compares the battery capacity at that time with the rated capacity.

Table 4.8-2 specifies the normal limits for each designated pilot cell and each connected cell forelectrolyte level, float voltage and specific gravity.

The limits for the designated pilot cells float voltage andspecific

gravity, greater than 2.13 volts and .015 below the manufacturer's full charge specific gravity or abattery charger current that had stabilized at a low value, is characteristic of a charged cell with adequatecapacity.

The normal limits for each connected cell for float voltage and specific

gravity, greater than2.13 volts and not more than .020 below the manufacturer's full charge specific gravity with an averagespecific gravity of all the connected cells not more than .010 below the manufacturer's full charge specificgravity, ensures the OPERABILITY and capability of the battery.Operation with a battery cell's parameter outside the normal limit but within the allowable valuespecified in Table 4.8-2 is permitted for up to 7 days. During this 7 day period: (1) the allowable valuesfor electrolyte level ensures no physical damage to the plates with an adequate electron transfercapability; (2) the allowable value for the average specific gravity of all the cells, not more than .020 belowthe manufacturer's recommended full charge specific

gravity, ensures that the decrease in rating will beless than the safety margin provided in sizing; (3) the allowable value for an individual cell's specificgravity, ensures that an individual cell's specific gravity will not be more than .040 below themanufacturer's full charge specific gravity and that the overall capability of the battery will be maintained within an acceptable limit; and (4) the allowable value for an individual cell's float voltage, greater than2.07 volts, ensures the battery's capability to perform its design function.

The test listed below is a means of determining whether new fuel oil is of the appropriate gradeand has not been contaminated with substances that would have an immediate, detrimental impact ondiesel engine combustion.

If the results from this test is within acceptable limits, the fuel oil may beadded to the storage tanks without concern for contaminating the entire volume of fuel oil in the storageDecember 21, 2012SEQUOYAH

-UNIT 2 B 3/4 8-7 Amendment No. 12, 137, 250, 252, 325 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued) tanks. This test is to be conducted prior to adding the new fuel to the storage tank(s),

but in no case isthe time between receipt of new fuel and conducting the test to exceed 31 days. The test, limits, andapplicable ASTM Standards are as follows:a. Sample the new fuel in accordance with D4057-1988 (ref.);b. Verify in accordance with the test specified in ASTM D975-1990 (Ref.) that the sample has anabsolute specific gravity at 60/60 degrees F of _> 0.83 and _< 0.89 or an API gravity at 60 degrees F of>_ 27 degrees and < 39 degrees, a kinematic viscosity at 40 degrees C of > 1.9 centistokes and < 4.1centistokes, and a flash point of >_ 125 degrees F; andc. Verify that the new fuel oil has a clear and bright appearance with proper color when tested inaccordance with ASTM D4176-1986 (Ref.).Failure to meet any of the above limits is cause for rejecting the new fuel oil, but does not represent afailure to meet LCO concern since the fuel oil is not added to the storage tanks.Within 31 days following the initial new fuel oil sample, the fuel oil is analyzed to establish that theother properties specified in Table 1 of ASTM D975-1990 (Ref.) are met, except that the analysis forsulfur may be performed in accordance with ASTM D1 552-1990 (Ref.) or ASTM D2622-1987 (Ref.). The31 day period is acceptable because the fuel oil properties of interest, even if they were not within statedlimits, would not have an immediate effect on DIG operation.

This surveillance ensures availability of highquality fuel oil for the D/Gs.Fuel oil degradation during long term storage shows up as an increase in particulate, due mostly tooxidation.

The presence of particulate does not mean the fuel oil will not burn properly in a diesel engine.The particulate can cause fouling of filters and fuel oil injection equipment,

however, which can causeengine failure.Particulate concentrations should be determined in accordance with ASTM D2276-94, Method A(Ref.). This method involves a gravimetric determination of total particulate concentration in the fuel oiland has a limit of 10 mg/I. It is acceptable to obtain a field sample for subsequent laboratory testing inlieu of field testing.

Each of the four interconnected tanks which comprise a 7-day tank must beconsidered and tested separately.

The frequency of this test takes into consideration fuel oil degradation trends that indicate thatparticulate concentration is unlikely to change significantly between frequency intervals.

References:

ASTM Standards D4057-1988, "Practice for manual sampling of petroleum and petroleum Products."

D975-1990, "Standard Specifications for Diesel Fuel oils."D4176-1986, "Free Water and Particulate Contamination in Distillate Fuels."D1552-1990, "Standard Test Method for Sulfur in Petroleum Products (High Temperature Method)."

December 21, 2012SEQUOYAH

-UNIT 2 B 3/4 8-8 Amendment No. 123, 241, 252 3/4.8 ELECTRICAL POWER SYSTEMSBASES3/4.8.1 and 3/4.8.2 A.C. SOURCES AND ONSITE POWER DISTRIBUTION SYSTEMS (Continued)

D2622-1987, "Standard Test Method for Sulfur in Petroleum Products (X-Ray Spectrographic Method)."

D2276-1994, "Standard Test Method for Particulate Containment in Aviation Turbine Fuels."D1298-1985, "Standard Test Method for Density, Specific

Gravity, or API Gravity of Crude Petroleum andLiquid Petroleum Products by Hydrometer Method."3/4.8.3 ELECTRICAL EQUIPMENT PROTECTIVE DEVICESThis specification is deleted.SEQUOYAH

-UNIT 2December 21, 2012Amendment No. 123, 241, 252B 3/4 8-9

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