ML14335A629

Basis for Proposed Changes. Part 2 of 2

ML14335A629
Person / Time
Site:	Farley
Issue date:	11/24/2014
From:	Southern Nuclear Operating Co
To:	Office of Nuclear Reactor Regulation
Shared Package
ML14335A689	List: ML14335A623 ML14335A629 NL-14-1385, Basis for Proposed Changes. Part 1 of 2 NL-14-1385, Joseph M. Farley Nuclear Plant - Units 1 and 2 - Request for Technical Specification Amendment Adoption of Previously NRC-Approved Generic Technical Specification Changes and Other Changes
References
NL-14-1385
Download: ML14335A629 (162)

Text

Enclosure 2 to NL-14-1385 Marked-Up Technical Specifications Pages AC Sources -

Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.13 NOTES---------------

1.

This Surveillance shall be performed within 10 minutes of shutting down the DG after the DG has operated > 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded > 4075 kW for the 4075 kW DGs and _> 2850 kW for the 2850 kW DG.

Momentary transients below the minimum load specified do not invalidate this test.

2.

All DG starts may be preceded by an engine prelube period.

Verify each DG starts and achieves, in < 12 seconds, voltage > 3952 V and frequency _ 60 Hz.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.14 I--

I r------

This Surveillance shall not be performed in MODE 1, 2, 3, or 4. ý,

• ._no~rmaly ITTF283l Verify each DG:

a.

Synchronizes with o ite power source while loaded with emergenc loads upon a simulated restoration of offsite po er;

b.

Transfers loads to offsite ower source; and

c.

Returns to ready-to-load op ation.

In accordance with the Surveillance Frequency Control Program However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Farley Units 1 and 2 3.8.1-12 Amendment No. r(Unit 1)

Amendment No. 9 (Unit 2) to NL-14-1385 Marked-Up Technical Specifications Pages AC Sources-- Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.15 Verify, with a DG operating in test mode and In accordance with connected to its bus, an actual or simulated ESF the Surveillance actuation signal overrides the test mode by returning Frequency Control DG to ready-to-load operation.

Program SR 3.8.1.16 Verify interval between each sequenced load block is In accordance with within +/- 10% of design interval or 0.5 seconds, the Surveillance whichever is greater, for each emergency load Frequency Control sequencer.

Program SR 3.8.1.17 NOTES-------

1.

All DG starts may be preceded by an engine prelube period.

normally VEEKI

2.

This Surveillance shall not be performed in MODE 1, 2, 3, or 4.

Verify on an actual or sim lated loss of offsite power signal in conjunction with an actual or simulated ESF actuation signal:

a.

De-energization o emergency buses;

b.

Load shedding fr m emergency buses; and

c.

DG auto-starts f m standby condition and:

1.

energize permanently connected loads in _< 12 s conds, ITSTF-283 In accordance with the Surveillance Frequency Control Program (continued)

However, portions of the surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Farley Units 1 and 2 3.8.1-13 Amendment No.'i- (Unit 1)

Amendment No. 1 (Unit 2) to NL-14-1385 Marked-Up Technical Specifications Pages Distribution Systems -

Operating 3.8.9 3.8 ELECTRICAL POWER SYSTEMS 3.8.9 Distribution Systems -Operating LCO 3.8.9 APPLICABILITY:

Train A and Train B AC, DC, and AC vital bus electrical power distribution subsystems shall be OPERABLE.

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more AC electrical A.1 Restore AC electrical 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> power distribution power distribution subsystems inoperable, subsystem(s) to AN&

OPERABLE status.

%-6hos r-from diase*.*y ef failull t-,

meet--ee B.

One or more AC vital buses inoperable.

B.1 Restore AC vital bus subsystem(s) to OPERABLE status.

8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> d

0ry

[f Fdilut to mest-L-.G C.

One Auxiliary Building DC C.1 Restore Auxiliary 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> electrical power distribution Building DC electrical subsystem inoperable, power distribution AN_-

subsystem to OPERABLE status.

46-heUF.er ldVisey of falure LO Farley Units 1 and 2 3.8.9-1 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Marked-Up Technical Specifications Pages Boron Concentration 3.9.1 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration LCO 3.9.1 Boron concentrations of the Reactor Coolant System, the refueling canal, and the refueling cavity shall be maintained within the limit specified in the COLR.

APPLICABILITY:

.....................................- N O T E MODE 6. Only applicable to the refueling canal and refueling cavity when connected to the RCS.

-I ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Boron concentration not A.1 Suspend CORE Immediately within limit.

ALTERATIONS.

AND A.2 Suspend positive Immediately reactivity additions.

AND A.3 Initiate action to restore Immediately boron concentration to within limit.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.1.1 Verify boron concentration is within the limit specified In accordance with in COLR.

the Surveillance Frequency Control Program Farley Units 1 and 2 3.9.1-1 Amendment No. E (Unit 1)

Amendment No. W (Unit 2) to NL-14-1385 Marked-Up Technical Specifications Pages Containment Penetrations 3.9.3 3.9 REFUELING OPERATIONS 3.9.3 Containment Penetrations LCO 3.9.3 The containment penetrations shall be in the following status:

a.

The equipment hatch is capable of being closed and held in place by four bolts;

b.

One door in each air lock is capable of being closed; and

c.

Each penetration providing direct access from the containment atmosphere to the outside atmosphere either:

1.

closed by a manual or automatic isolation valve, blind flange, or equivalent, or

2.

capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System.

ITSTF3 12 INSERT - LCO 3.9.3 Note-APPLICABILITY:

During CORE ALTERATIONS, During movement of irradiated fuel assemblies within containment.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more containment A.1 Suspend CORE Immediately penetrations not in ALTERATIONS.

required status.

AND A.2 Suspend movement of Immediately irradiated fuel assemblies within containment.

Farley Units 1 and 2 3.9.3-1 Amendment No. l (Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Marked-Up Technical Specifications Pages INSERT - LCO 3.9.3 Note ITTF312

---

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

Penetration flow path(s) providing direct access from the containment atmosphere to the outside atmosphere may be unisolated under administrative controls.

to NL-14-1385 Marked-Up Technical Specifications Pages Containment Penetrations 3.9.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.3.1 Verify each required containment penetration is in the In accordance required status.

with the Surveillance Frequency Control Program SR 3.9.3.2

ýerify each required containment purge and exhaust In accordance vaye actuates to the isolation position on an actual or with the sim ated actuation signal.

Surveillance Frequency Control Program SR 3.9.3.3

---

NOTE In accordance Only re uired for an open equipment hatch.

with the Surveillance Verify t e capability to install the equipment Frequency Control hatch.

Program FT=284 NOTE--

Not required to be met for containment purge and exhaust valve(s) in penetrations closed to comply with LCO 3.9.3.c. 1.

---

----- - I Farley Units 1 and 2 3.9.3-2 Amendment No.= (Unit 1)

Amendment No. W (Unit 2) to NL-14-1385 Marked-Up Technical Specifications Pages RHR and Coolant Circulation -

Low Water Level 3.9.5 3.9 REFUELING OPERATIONS 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation -

Low Water Level LCO 3.9.5 Two RHR loops shall be OPERABLE, and one RHR loop shall be in operation.

-E_9 One RHR loop may be inoperable and no RHR loop may be in the decay heat removal mode of operation for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for required surveillance INSERT - TS 3.9.5

.testing.

Note 2 APPLICABILITY:

MODE 6 with the water level < 23 ft above the top of reactor vessel flange.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Less than the required A.1 Initiate action to restore Immediately number of RHR loops required RHR loops to OPERABLE.

OPERABLE status.

OR A.2 Initiate action to Immediately establish _> 23 ft of water above the top of reactor vessel flange.

B.

No RHR loop in operation.

B.1 Suspend operations Immediately involving a reduction in reactor coolant boron concentration.

AND (continued)

Farley Units 1 and 2 3.9.5-1 Amendment No. G (Unit 1)

Amendment No. Eýý-(Unit 2) to NL-14-1385 Marked-Up Technical Specifications Pages INSERT - TS 3.9.6 Note 2

2. All RHR pumps may be de-energized for < 15 minutes when switching from one train to another provided:

a. The core outlet temperature is maintained > 10 degrees F below saturation temperature;

b. No operations are permitted that would cause a reduction of the Reactor Coolant System (RCS) boron concentration; and

c. No draining operations to further reduce RCS water volume are permitted.

to NL-14-1385 Marked-Up Technical Specifications Pages Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.4 Radioactive Effluent Controls Program (continued)

b.

Limitations on the concentrations of radioactive material released in liquid effluents to unrestricted areas, conforming to 10 times the concentration stated in 10 CFR 20, Appendix B (to paragraphs 20.1001-20.2401),

Table 2, Column 2;

c.

Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.1302 and with the methodology and parameters in the ODCM;

d.

Limitations on the annual and quarterly doses or dose commitment to a member of the public from radioactive materials in liquid effluents released from each unit to unrestricted areas, conforming to 10 CFR 50, Appendix I; e.

Beterrmimatiam ef eumiulative and prejeeted dese eenR~ibution3fro radiesetive effluerits for the eurrermt ealemder quarter arid eurreit esl~dar

o~rin coodanee with the methedelegy and pefanmzters in the 00CM at, ea~ e~r~31 dy's;'

ITSTF-30q

f.

Limitations on the functi nal capability and use of the liquid and gaseous effluent treatment syste s to ensure that appropriate portions of these systems are used to re uce releases of radioactivity when the projected doses in a period of 31 days would exceed 2% of the guidelines for the annual dose or dose c mmitment, conforming to 10 CFR 50, Appendix I;

g.

Limitations on the do e rate resulting from radioactive material released in gaseous effluents to reas at and beyond the site boundary as follows:

1.

For noble gase : Less than or equal to a dose rate of 500 mrem/year to the total bo and less than or equal to a dose rate of 3000 mrem/year to e skin, and

2.

For Iodine-1

, Iodine-133, tritium, and for all radionuclides in particulate f m with half lives greater than 8 days: Less than or equal to a dose ra of 1500 mrem/year to any organ.

h.

Limitations on t annual and quarterly air doses resulting from noble gases released n gaseous effluents from each unit to areas beyond the site boundary, onforming to 10 CFR 50, Appendix I; Determination of cumulative dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days. Determination of projected dose contributions from radioactive effluents in accordance with the methodology in the ODCM at (continued) east every 31 days.

Farley Units 1 and 2 5.5-3 Amendment No.

-I-I(Unit 1)

Amendment No. F (Unit 2)

I to NL-14-1385 Marked-Up Technical Specifications Pages Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)

b.

Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;

c.

Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and no concurrent loss of offsite power or no

d.

Other appropriate limitations and remedial or compensatory actions.

concurrent loss of onsite diesel A loss of safety function exists when, assuming no concurrent single failure, a generator(s),

safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a.

A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or Irs When a loss of safety

b.

A required system redundant to the system(s) in turn supported by the function is caused by inoperable supported system is also inoperable; or inoperability of a single Technical Specification

c.

A required system redundant to the support system(s) for the supported support system, the systems (a) and (b) above is also inoperable.

appropriate Conditions The SFDP identifies *here a loss of safety function exists. If a loss of safety and Required Actions to function is determine to exist by this program, the appropriate Conditions and enter are those of the Required Actions of th* LCO in which the loss of safety function exists are support system.

required to be entered.

5.5.16 Main Steamline Inspection Program The three main steamlines from the rigid anchor points of the containment penetrations downstream to and including the main steam header shall be inspected. The extent of the inservice examinations completed during each inspection interval (IWA 2400, ASME Code, 1974 Edition,Section XI) shall provide 100 percent volumetric examination of circumferential and longitudinal pipe welds to the extent practical. The areas subject to examination are those defined in accordance with examination category C-G for Class 2 piping welds in Table IWC-2520.

5.5.17 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of containment as required by 10 CFR 50.54 (o) and 10 CFR 50, Appendix J, (continued)

Farley Units 1 and 2 5.5-13 Amendment No. Fii(Unit 1)

Amendment No.

-'(Unit 2) to NL-14-1385 Marked-Up Technical Specifications Pages Programs and Manuals 5.5 5.5 Programs and Manuals P

5.5.17 Containment Leakage Rate Testing Program (continued)

Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guidelines for Implementing Performance-Based Option of 10 CFR 50, Appendix J":

Se etiong 1.2.3: The next Type A test, efter the MBroh 1004 tect for UnWit 1 and the MSroh 1905 test for Unit 2, chall be perfoirmod dunin rofuoling outage R22 (SpbRig 2000) for Unit I 8191d durig iefuelfi ouag R2e (Gpiiig 2010) for Un1 t 2. This is a on time emeeeotin.

SectioINSER

,5.5.17 The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 43.8 psig.

The maximum allowable containment leakage rate, La, at Pa, is 0.15% of containment air weight per day.

Leakage rate acceptance criteria are:

a.

Containment overall leakage rate acceptance criterion is _ 1.0 La. During plant startup following testing in accordance with this program, the leakage rate acceptance criteria are <_ 0.60 La for the combined Type B and C tests, and < 0.75 La for Type A tests;

b.

Air lock testing acceptance criteria are:

1.

Overall air lock leakage rate is _< 0.05 La when tested at _>

Pa.

2.

For each door, leakage rate is < 0.01 La when pressurized to > 10 psig.

c.

During plant startup following testing in accordance with this program, the leakage rate acceptance criterion for each containment purge penetration flowpath is < 0.05 La The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

(continued)

Farley Units 1 and 2 5.5-14 Amendment No. =(Unit 1)

Amendment No. -e(Unit 2)I to NL-14-1385 Marked-Up Technical Specifications Pages INSERT - Section 5.5.17

1. The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

2. The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section Xl code, Subsection IWE, except where relief has been authorized by the NRC.

Joseph M. Farley Nuclear Plant - Units 1 and 2 Request for Technical Specification Amendment Adoption of Previously NRC-Approved Generic Technical Specification Changes and Other Changes Example Marked-Up Technical Specifications Bases Pages Example Marked-Up Technical Specifications Bases Pages Index of Affected Technical Specification Bases Pages vs.. Traveler or Change Traveler(s) or Page Change TSTF-273-A B3.0-10 TSTF-314-A B3.1.4-7 TSTF-315-A B3.1.8-5 TSTF-314-A B3.2.4-3 TSTF-314-A B3.2.4-5 TSTF-355-A B3.3.1-1 TSTF-355-A B3.3.1-2 TSTF-355-A B3.3.1-4 TSTF-355-A B3.3.1-5 TSTF-355-A B3.3.1-7 TSTF-371 -A B3.3.1-50 TSTF-371 -A B3.3.1-51 TSTF-371-A B3.3.1-52 TSTF-355-A B3.3.1-61 TSTF-355-A B3.3.2-1 TSTF-355-A B3.3.2-3 TSTF-355-A B3.3.2-4 TSTF-355-A B3.3.2-5 ISTS Adoption #1 B3.3.2-33 ISTS Adoption #1 B3.3.2-36 TSTF-266-A B3.3.4-2 TSTF-266-A B3.3.4-3 TSTF-266-A B3.3.4-6 TSTF-27-A B3.4.2-3 TSTF-87-A B3.4.5-1 TSTF-87-A B3.4.5-2 TSTF-87-A B3.4.5-4 TSTF-87-A B3.4.5-5 TSTF-87-A B3.4.9-3 TSTF-247-A B3.4.11-4 TSTF-247-A B3.4.11-6 TSTF-284-A B3.4.11-7 TSTF-284-A B3.4.11-8 TSTF-284-A B3.4.12-11 TSTF-325-A B3.5.2-7 TSTF-325-A B3.5.2-8 Vogtle Change #1 B3.5.5-3 Vogtle Change #1 B3.5.5-4 TSTF-343-A B3.6.1-4 TSTF-46-A B3.6.3-12 TSTF-439-A B3.6.6-6 TSTF-439-A B3.6.6-7 TSTF-340-A B3.7.5-5 TSTF-340-A, B3.7.5-6 TSTF-439-A TSTF-245-A B3.7.5-8 TSTF-245-A B3.7.5-9 TSTF-439-A B3.8.1-8 TSTF-439-A B3.8.1-11 TSTF-283-A B3.8.1-20 TSTF-283-A B3.8.1-22 TSTF-283-A B3.8.1-25 TSTF-283-A B3.8.1-27 TSTF-439-A B3.8.9-4 TSTF-439-A B3.8.9-5 TSTF-439-A 83.8.9-6 TSTF-439-A B3.8.9-8 TSTF-272-A B3.9.1-3 TSTF-272-A B3.9.1-4 TSTF-312-A B3.9.3-4 TSTF-284-A B3.9.3-6 TSTF-349-A 83.9.5-2 E3-1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages LCO Applicability B 3.0 BASES LCO 3.0.6 (continued)

EXAMPLE B3.0.6-2 If System 2 of Train A is inoperable, and System 11 of Train B is inoperable, a loss of safety function exists in System 11 which is in turn supported by System 5.

EXAMPLE B3.0.6-3 If System 2 of Train A is inoperable, and System 1 of Train B is inoperable, a loss of safety function exists in Systems 2, 4, 5, 8, 9, 10 and 11.

If this evaluation determines that a loss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

EXAMPLES TRAIN A TRAIN B System 4 System 2 System 5 System 1 System 6 System 3 System 7 IINSERT - LCO 3.0.6 Bases System 8 System 9 System 10 System 11 System 12 System 13 System 14 System 15 System 1 System 4 System 2 System 5 System 6 System 3 System 7 System 8 System 9 System 10 System 11 System 12 System 13 System 14 System 15 LCO 3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit. These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance activities, and to perform special evolutions. Test Exception LCO 3.1.8 allows specified Technical (continued)

Farley Units 1 and 2 B 3.0-10 Revision FV%)

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT - LCO 3.0.6 Bases ITSTF-273 I This loss of safety function does not require the assumption of additional single failures or loss of offsite power. Since operation is being restricted in accordance with the ACTIONS of the support system, any resulting temporary loss of redundancy or single failure protection is taken into account. Similarly, the ACTIONS for inoperable offsite circuit(s) and inoperable diesel generator(s) provide the necessary restriction for cross train inoperabilities. This explicit cross train verification for inoperable AC electrical power sources also acknowledges that supported system(s) are not declared inoperable solely as a result of inoperability of a normal or emergency electrical power source (refer to the definition of OPERABILITY).

When a loss of safety function is determined to exist, and the SFDP requires entry into the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists, consideration must be given to the specific type of function affected. Where a loss of function is solely due to a single Technical Specification support system (e.g., loss of automatic start due to inoperable instrumentation, or loss of pump suction source due to low tank level) the appropriate LCO is the LCO for the support system. The ACTIONS for a support system LCO adequately addresses the inoperabilities of that system without reliance on entering its supported system LCO. When the loss of function is the result of multiple support systems, the appropriate LCO is the LCO for the supported system.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Rod Group Alignment Limits B 3.1.4 BASES ACTIONS (continued)

B.2.2. B.2.3. B.2.4. B.2.5. and B.2.6 For continued operation with a misaligned rod, RTP must be reduced, SDM must periodically be verified within limits, hot channel factors (FQ(Z) and FNH) must be verified within limits, and the safety analyses must be re-evaluated to confirm continued operation is permissible.

Reduction of power to 75% RTP ensures that local LHR increases due to a misaligned RCCA will not cause the core design criteria to be exceeded. The Completion Time of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> gives the operator sufficient time to accomplish an orderly power reduction without challenging the Reactor Protection System.

JINSERT - Bases 3.1.4 Action When a rod is known to be misaligned, there is a potential to impact the SDM. Since the core conditions can change with time, periodic verification of SDM is required. A Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient to ensure this requirement continues to be met.

Verifying that Fa(Z) and FAH are within the required limits ensures that current operation at 75% RTP with a rod misaligned is not resulting in power distributions that may invalidate safety analysis assumptions at full power. The Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allows sufficient time to obtain flux maps of the core power distribution using the incore flux mapping system and to calculate FQ(Z) and FNH*

Once current conditions have been verified acceptable, time is available to perform evaluations of accident analysis to determine that core limits will not be exceeded during a Design Basis Event for the duration of operation under these conditions. A Completion Time of 5 days is sufficient time to obtain the required input data and to perform the analysis.

The following accident analyses are required to be reevaluated:

1. Rod Cluster Control Assembly Insertion Characteristics;

2. Rod Cluster Control Assembly Misalignment;

3. Loss Of Reactor Coolant From Small Ruptured Pipes or From Cracks In Large Pipes Which Actuates The Emergency Core Cooling System; (continued)

Farley Units 1 and 2 B 3.1.4-7 RevisionrF1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT - BASES 3.1.4 Action

, as approximated by the steady state and transient FQ(Z),

ITsTF-31 4I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages PHYSICS TESTS Exceptions - MODE 2 B 3.1.8 BASES APPLICABLE SAFETY ANALYSES (continued) not violated. When one or more of the requirements specified in LCO 3.1.3, "Moderator Temperature Coefficient (MTC)," LCO 3.1.4, LCO 3.1.5, LCO 3.1.6, and LCO 3.4.2 are suspended for PHYSICS TESTS, the fuel design criteria are preserved as long as the power level is limited to = 5% RTP, the reactor coolant temperature is kept

= 531°F, and SDM is within the limits provided in the COLR.

The PHYSICS TESTS include measurement of core nuclear parameters or the exercise of control components that affect process variables. Among the process variables involved are AFD and QPTR, which represent initial conditions of the unit safety analyses. Also involved are the movable control components (control and shutdown rods), which are required to shut down the reactor. The limits for these variables are specified for each fuel cycle in the COLR.

PHYSICS TESTS meet the criteria for inclusion in the Technical Specifications, since the components and process variable LCOs suspended during PHYSICS TESTS meet Criteria 1, 2, and 3 of 10 CFR 50.36 (c)(2)(ii).

Reference 6 allows special test exceptions (STEs) to be included as part of the LCO that they affect. It was decided, however, to retain this STE as a separate LCO because it was less cumbersome and provided additional clarity.

LCO One Power Range Neutron Flux Channel may be bypassed, reducing the number of required channels from 4 to 3.

This LCO allows the reactor parameters of MTC and minimum temperature for criticality to be outside their specified limits. In addition, it allows selected control and shutdown rods to be positioned outside of their specified alignment and insertion limits Operation lTSTF-315 I beyond specified limits is permitted for the purpose of *erforming PHYSICS TESTS and poses no threat to fuel integrity provided the SRs are met.

/

The requirements of LCO 3.1.3, LCO 3.1.4, LCO 3.1.5, LCO 3.1.6, and LCO 3.4.2 may be suspended ring the performance of PHYSICS TESTS provided:

and the i= 5%

required aLCO 3.3 lnctr" ino number of channels for

.1, "RTS

.ntation,"

s 2, 3, and y be reduced

b. SDM is within the limits provided in the COLR; and

c. RCS lowest loop average temperature is = 5310F.

Function 17.e, ma to 3 Farley Units 1 and 2 B 3.1.8-5 RevisionED to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages QPTR B 3.2.4 BASES ACTIONS A.I1 With the QPTR exceeding 1.02, limiting THERMAL POWER to

> 3% below RTP for each 1% by which the QPTR exceeds 1.00 is a conservative tradeoff of total core power with peak linear power. The Completion Time of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after each determination of QPTR allows sufficient time to identify the cause and correct the tilt. Note that the power reduction itself may cause a change in the tilted condition.

The maximum allowable THERMAL POWER level initially determined by Required Action A.1 may be affected by subsequent determinations of QPTR in Required Action A.2. Increases in QPTR would require a THERMAL POWER reduction within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of QPTR determination, if necessary to comply with the decreased maximum allowable THERMAL POWER level. Conversely, decreases in QPTR would allow raising the maximum allowable THERMAL POWER level and increasing THERMAL POWER up to this revised limit.

A.2 After completion of Required Action A. 1, the QPTR alarm may still be in its alarmed state. As such, any additional changes in the QPTR are detected by requiring a check of the QPTR once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. If the QPTR continues to increase, THERMAL POWER has to be reduced according to Required Action A. 1. A 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is sufficient because any additional change in QPTR would be relatively slow.

A.3 INSERT - Bases 3.2.4 Action The peaking factors F AH and FQ(Z) are of primary importance in L2 ensuring that the power distribution remains consistent with the initial conditions used in the safety analyses. Performing SRs on FNH and FQ(Z) within the Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after achieving equilibrium conditions from a THERMAL POWER reduction required by Required Action A.1 ensures that these primary indicators of power distribution are within their respective limits. Equilibrium conditions are achieved when the core is sufficiently stable at the intended operating conditions to support flux mapping. The above Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after achieving equilibrium conditions from a THERMAL POWER reduction required by Required Action A.1 takes into consideration the rate at which peaking factors are likely to (continued)

Farley Units 1 and 2 B 3.2.4-3 Revision F1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT - BASES 3.2.4 Action

, as approximated by the steady state and transient FQ(Z),

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages QPTR B 3.2.4 BASES ACTIONS A.5 (continued) calibration of the NIS or through the use of constants in calculations) in such a manner that the indicated QPTR following normalization is near 1.00. This is done to detect any subsequent significant changes in QPTR.

Required Action A.5 is modified by two Notes. Note 1 states that the QPTR is not restored to within limits until after the re-evaluation of the safety analysis has determined that core conditions at RTP are within the safety analysis assumptions (i.e., Required Action A.4). Note 2 states that if Required Action A.5 is performed, then Required Action A.6 shall be performed. Required Action A.5 normalizes the excore detectors to restore QPTR to within limits, which restores compliance with LCO 3.2.4. Thus, Note 2 prevents exiting the Actions prior to completing flux mapping to verify peaking factors, per Required Action A.6. These Notes are intended to prevent any ambiguity about the required sequence of actions.

A.6 IINSERT - Bases 3.2.4 Action Once the excore detectors are normalized to restore QPTR to within limits (i.e., Required Action A.5 is performed), it is acceptable to retu to full power operation. However, as an added check that the core power distribution at RTP is consistent with the safety analysis FT 3

assumptions, Required Action A.6 requires verification that FQ(Z) nd FH are within their specified limits within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after achieving equilibrium conditions at RTP. Required Action A.6 also states that the peaking factor surveillance must be performed within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after increasing THERMAL POWER above the limit of Required Action A.1. This is an added precaution in the event that RTP is not achieved in a timely manner. These Completion Times are intended to allow adequate time to increase THERMAL POWER to above the limit of Required Action A. 1, while not permitting the core to remain with unconfirmed power distributions for extended periods of time.

Required Action A.6 is modified by a Note that states that the peaking factor surveillances may only be done after the excore detectors have been normalized to restore QPTR to within limits (i.e., Required Action A.5). The intent of this Note is to have the peaking factor (continued)

Farley Units 1 and 2 B 3.2.4-5 Revisionr=

r17 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 B 3.3 INSTRUMENTATION B 3.3.1 Reactor Trip System (RTS) Instrumentation BASES BACKGROUND The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and Reactor Coolant System (RCS) pressure boundary during anticipated operational occurrences (AOOs) and to assist the Engineered Safety Features (ESF) Systems in mitigating accidents.

The protection and monitoring systems have been designed to assure safe operation of the reactor. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RTS, as well as specifying LCOs on other reactor system ITSTF-355

+a' rr1ae

,nda lm' 4

+

r4nr,.

a I n s e r t 1 - B a s e s 3.3.1 V "1 " u u io' u lu, u

p4u i,*,,I I,,I 1,,1J,

-tI

,,',I.

Background

The LSC8, defined in this specifcatio.n as the.p T

t.. It...

enjunetien with the LCO39, establish the thIFr-hld f-r pr-;

r.,

setien to prevent emeeeding eeeeptable limfitG during Design Bai Aeeident9 (DB6Ns).

~-sys~eti~

During AOOs, which are those events expected to occur one or more times during the unit life, the acceptable limits are:

1. The Departure from Nucleate Boiling Ratio (DNBR) shall be maintained above the Safety Limit (SL) value to prevent departure from nucleate boiling (DNB);

2. Fuel centerline melt shall not occur; and

3. The RCS pressure SL of 2735 psig shall not be exceeded.

Operation within the SLs of Specification 2.0, "Safety Limits (SLs)," also maintains the above values and assures that offsite dose will be within the 10 CFR 50 and 10 CFR 100 criteria during AOOs.

Accidents are events that are analyzed even though they are not expected to occur during the unit life. The acceptable limit during accidents is that offsite dose shall be maintained within an acceptable fraction of 10 CFR 100 limits. Different accident categories are allowed (continued)

Farley Units 1 and 2 B 3.3. 1-1 Revisionria--i r", 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert I - Bases 3.3.1 Background ITSTF-355 Technical specifications are required by 10CFR50.36 to contain LSSS defined by the regulation as ".... settings for automatic protective devices.., so chosen that automatic 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 by the safety analysis, to ensure that a SL is not exceeded.

Any automatic protection action that occurs on reaching the Analytic Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protective devices must be chosen to be more conservative than the Analytic Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.

The Trip Setpoint is a predetermined setting for a protective device chosen to ensure automatic actuation prior to the process variable reaching the Analytic Limit and thus ensuring that the SL would not be exceeded. As such, the Trip Setpoint accounts for uncertainties in setting the device (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 any other factors which may influence its actual performance (e.g., harsh accident environments). In this manner, the Trip Setpoint plays an important role in ensuring that SLs are not exceeded. As such, the Trip Setpoint meets the definition of an LSSS (Ref. 23) and could be used to meet the requirement that they be contained in the technical specifications.

Technical specifications contain values related to the OPERABILITY of equipment required for safe operation of the facility. Operable is defined in technical specifications as "... being capable of performing its safety function(s)." For automatic protective devices, the required safety function is to ensure that a SL is not exceeded and therefore the LSSS as defined by 10 CFR 50.36 is the same as the OPERABILITY limit for these devices. However, use of the Trip Setpoint to define OPERABILITY in technical specifications and its corresponding designation as the LSSS required by 10 CFR 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 which are not necessary to ensure safety. For example, an automatic protective device with a setting that has been found to be different from the Trip Setpoint due to some drift of the setting may still be OPERABLE since drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the 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 the protective device. Therefore, the device would still be OPERABLE since it would have performed its safety function and the only corrective action required would be to reset the device to the Trip Setpoint to account for further drift during the next surveillance interval.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert I - Bases 3.3.1 Background (continued)

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

However, there is also some point beyond which the device would have not been able to perform its function due, for example, to greater than expected drift. This value needs to be specified in the technical specifications in order to define OPERABILITY of the devices and is designated as the Allowable Value which, as stated above, is the same as the LSSS.

The Allowable Value specified in Table 3.3.1-1 serves as the LSSS such that a channel is OPERABLE if the trip setpoint is found not to exceed the Allowable Value during the CHANNEL OPERATIONAL TEST (COT). As such, the Allowable Value differs from the Trip Setpoint by an amount primarily equal to the expected instrument loop uncertainties, such as drift, during the surveillance interval. In this manner, the actual setting of the device will still meet the LSSS definition and ensure that a Safety Limit is not exceeded at any given point of time as long as the device has not drifted beyond 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 trip setpoint calibration tolerance band, in accordance with uncertainty assumptions stated in the referenced setpoint methodology (as-left criteria),

and confirmed to be operating within the statistical allowances of the uncertainty 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. This requires corrective action including those actions required by 10 CFR 50.36 when automatic protective devices do not function as required.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 BASES BACKGROUND a different fraction of these limits, based on probability of occurrence.

(continued)

Meeting the acceptable dose limit for an accident category is considered having acceptable consequences for that event.

The RTS instrumentation is segmented into four distinct but interconnected modules as illustrated in functional diagrams referenced in the FSAR, Chapter 7 (Ref. 1), and as identified below:

1. Field transmitters or process sensors: provide a measurable electronic signal based upon the physical characteristics of the parameter being measured;

2. Signal Process Control and Protection System, including Analog Protection System, Nuclear Instrumentation System (NIS), field contacts, and protection channel sets: provides signal conditioning, bistable setpoint comparison, process algorithm actuation, compatible electrical signal output to protection system devices, and control board/control room/miscellaneous indications;

3. Solid State Protection System (SSPS), including input, logic, and output bays: initiates proper unit shutdown and/or ESF actuation in accordance with the defined logic, which is based on the bistable outputs from the signal process control and protection system; and

4. Reactor trip switchgear, including reactor trip breakers (RTBs) and bypass breakers: provides the means to interrupt power to the control rod drive mechanisms (CRDMs) and allows the rod cluster control assemblies (RCCAs), or "rods," to fall into the core and shut down the reactor. The bypass breakers allow testing of the RTBs at power.

ITSTF-3 Field Transmitters or Sensors To meet the design demands for redundancy and reliability, more than one, and in some cases as many as four, field transmitters or sensors are used to measure unit parameters. To account for the calibration trip setpoint tolerances and instrument drift, which are assumed to occur between and calibrations, statistical allowances are provided in the Allowable The OPERABILITY of each transmitter or sensor,*, b,

Allow when its "asi feund" oulibrotioin date aro comAparod against its aus

.......... d.,

ptaneiF'

• f is determined by either "as-found" calibration data evaluated during the CHANNEL CALIBRATION or by qualitative assessment of field transmitter or sensor as related to the channel behavior observed during performance of the CHANNEL CHECK.

(continued)

Farley Units 1 and 2 B 3.3.1-2 Revision to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 BASES BACKGROUND Signal Process Control and Protection System (continued) such that testing required while the reactor is at power may be accomplished without causing trip. Provisions to allow removing logic channels from service during maintenance are unnecessary because of the logic system's designed reliability.

AValueand RTS Setpoints

[

The T,-;p Setpo;irl; aw e the vaue speifed 0I th e Teel, tcal Specificatins. The Nonia T i i Setpa;11ts are the target values at whtieh the field devioee anld bistables are set withim the ealibratien banld that "9 established en the oonmorvotive side of the TrFip Gctpoint. Any freteotion system ehonnol io eensiderzd te be PFprodry Sdjusted when the "as left" value is within the barid for eCl ANNEL= CALIRATION trip setpoints trip se ed are based ontheanI i m iti ted in References 3 and 6. The selection of these.Ti.t is such that adequate protection is provided when all sensor and processing time delays are taken into account. To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment 1conservative errors for those RTS channels that must function in harsh environments as defined by 10 CFR 50.49 (Ref. 6), the AAllowable Values specified in TabI 3.3.11-1 in the accompanying LCO are A*-lowable

ýeseyaivlyaeiuteW~ith respect to the analytical limits. A detail d Vle n description of the methodology used to calculate thel~i,ý trpN~l saponds Insert 2 - Bases 3.3.1 including their explicit uncertainties, is provided in the RTS/ESFAS B-/ackground Set oint Methodoloy Studys(Ref.7)n The.-- fk-j-

-A 4uainI Trip setpoints consistent detetabe bya CT.

re eampe ofsuo a hange in-moasurofment rrorF io drift dur~ing the sur~eillanse intorwal. if the moasburod setpoint Ao-I #4~

vo-f---.lt Allo-wk W.ll-"lIma ti-ia Wa*imtaln iti prni

-r44-A I

ABLE.

r-frequirements Ofthe

• -ents n

e, ith the Allowable Value ensure that SLs are not violated during AOOs (and that the consequences of DBAs will be acceptable, providing the unit is operated from within the LCOs at the onset of the AOO or DBA and the equipment functions as designed).

Each channel of the process control equipment can be tested on line to verify that the signal or setpoint accuracy is within the specified (continued)

Farley Units 1 and 2 B 3.3.1-4 Revisionl`291 I - I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert 2 - Bases 3.3.1 Background FTSTF-355 which incorporates all of the known uncertainties applicable to each channel. The magnitudes of these uncertainties are factored into the determination of each trip setpoint and corresponding Allowable Value. The trip setpoint entered into the bistable is more conservative than that specified by the Allowable Value (LSSS) to account for measurement errors detectable by the COT. The Allowable Value serves as the Technical Specification OPERABILITY limit for the purpose of the COT. One example of such a change in measurement error is drift during the surveillance interval. If the measured setpoint does not exceed the Allowable Value, the bistable is considered OPERABLE.

The trip setpoint is the value at which the bistable is set and is the expected value to be achieved during calibration. The trip setpoint value ensures the LSSS and the safety analysis limits are met for the surveillance interval selected when a channel is adjusted based on stated channel uncertainties. Any bistable is considered to be properly adjusted when the "'as left" setpoint value is within 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 COT and CHANNEL CALIBRATION.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 BASES and RTS Setpoints BACKGROUND ITm

,, Ilowable Values (continued) allowance requirements. Once a designated channel is taken out of service for testing, a simulated signal is injected in place of or superimposed on the field instrument signal. The process equipment for the channel in test is then tested, verified, and if required, calibrated.

. 1-SRs for the channels are specified in the SRs section.

The Trip Setpoints and Allowabl, Value listed

.i..Table 3.3.1 1 are based on the methcdelgie3 d.....b.d in Referzncza 7, 8, and 0, which-ateip i all of t k...wi..i. ice,.

.i.

i

.t.

. -ppl.abl.

for e h ehennzl.

h he magnltudes uf tihee uiii taild

-Itid a

,-du, d into the dete miatiom of eah Trp it, All f-,

t is s ad -:---

pF998c6ing oqIUipmon1Rt for there ehonncl3 erc assumcd to apefete within1 the ollowanecc of theco uncortainty magnitudo5.

Solid State Protection System The SSPS equipment is used for the decision logic processing of inputs from field contacts and control board switches and the signal processing equipment bistables. To meet the redundancy requirements, two trains of SSPS, each performing the same functions, are provided. If one train is taken out of service for maintenance or test purposes, the second train will provide reactor trip and/or ESF actuation for the unit. If both trains are taken out of service or placed in test, a reactor trip will result.

The reactor trip may be caused by a General Warning alarm in both trains or if both RTB bypass breakers BYA and BYB are racked in and closed. Each train is packaged in its own cabinet for physical and electrical separation to satisfy separation and independence requirements. The system has been designed to trip in the event of a loss of power, directing the unit to a safe shutdown condition.

The SSPS performs the decision logic for actuating a reactor trip or ESF actuation, generates the electrical output signal that will initiate the required trip or actuation, and provides the status, permissive, and annunciator output signals to the main control room of the unit.

The input signals from field contacts, control board switches and bistable outputs from the signal processing equipment are sensed by the SSPS equipment and combined into logic matrices that represent combinations indicative of various unit upset and accident transients. If a required logic matrix combination is completed, the system will initiate a reactor trip or send actuation signals via master and slave relays to (continued)

Farley Units 1 and 2 B 3.3.1-5 Revision E_ý'

ffu I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY The RTS functions to maintain the SLs during all AOOs and mitigates the consequences of DBAs in all MODES in which the RTBs are closed.

Each of the analyzed accidents and transients can be detected by one or more RTS Functions. The accident analysis described in Reference 3 takes credit for most RTS trip Functions. RTS trip Functions not specifically credited in the accident analysis are qualitatively credited in the safety analysis and the NRC staff approved licensing basis for the unit. These RTS trip Functions may provide protection for conditions that do not require dynamic transient analysis to demonstrate Function performance. They may also serve as backups to RTS trip Functions that were credited in the accident analysis.

Insert - Bases 3.3.1 ASA The LCO requires all instrumentation performing an RTS Function, /

listed in Table 3.3.1-1 in the accompanying LCO, to be OPERABLE.

Typically, failure of any instrument renders the affected channel(s) iTF_355 inoperable and reduces the reliability of the affected Functions.

I J

The LCO generally requires OPERABILITY of two, three, or four channels in each instrumentation Function, two channels of Manual Reactor Trip in each logic Function, and two trains in each Automatic Trip Logic Function. Four OPERABLE instrumentation channels in a two-out-of-four configuration are required when one RTS channel is also used as a control system input or functional separation between the protection and control systems must be demonstrated as described in FSAR Section 7.2.2.3. This configuration accounts for the possibility of the shared channel failing in such a manner that it creates a transient that requires RTS action. In this case, the RTS will still provide protection, even with random failure of one of the other three protection channels. Three operable instrumentation channels in a two-out-of-three configuration are generally required when there is no potential for control system and protection system interaction that could simultaneously create a need for RTS trip and disable one RTS channel. The two-out-of-three and two-out-of-four configurations allow one channel to be tripped during maintenance or testing without causing a reactor trip. Specific exceptions to the above general philosophy exist and are discussed below.

(continued)

Farley Units 1 and 2 B 3.3.1-7 RevisionE7'ý-l 11U I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert - Bases 3.3.1 ASA A channel is OPERABLE with a trip setpoint value outside its calibration tolerance band provided the trip setpoint "as-found" value does not exceed its associated Allowable Value and provided the trip setpoint "as-left" value is adjusted to a value within the "as-left" calibration tolerance band of the Nominal Trip Setpoint. A trip setpoint may be set more conservative than the Nominal Trip Setpoint as necessary in response to plant conditions.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.1 Performance of the CHANNEL CHECK ensures that gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

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

A Note modifies SR 3.3.1.1. The Note provides a clarification that the source range instrumentation surveillance is only required when reactor power is < P-6 and that 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after power is reduced below P-6 is allowed for performing the surveillance for this instrumentation.

I The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1power range I heat balance calculation SR 3.3.1.2 Iresults exceed Power range SR 3.3.1.2 comp res the calorimetric heat balance c ulation to the Tw r

channel ou.: pt every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. If the calorimetri lle f.eJthelNO4 channel indicated power by more than + 2% RTP, the power range.i*

hannel is not declared inoperable, but must be adjusted If the

'power r

channel output cannot be properly adjusted, the chan Is declared inoperable.

[

AItw calorimetric is performed at part power (< 500/

TP), adjusting the 1power range N$L_.l~

channel indication in the increasing power d ction will assure a reactor trip below the safety analysis limit (:5 1. % RTP). Making no 1power range7 Iadjustment to th RiTchannel indication in e decreasing power TSF371I The power range channel output shall be adjusted consistent with the calorimetric heat balance calculation results if the calorimetric calculation exceeds the power range channel output by more than + 2% RTP.

(continued)

Farley Units 1 and 2 B 3.3.1-50 Revisio-r_'ý F=

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 BASES FTSTF-37 1 01 ID\\IEII I AKlf' 00

'1 ". 4 13 I,-,

+,,-.,

A

%JJI'I,

• V,*NT*

oJI

,J.,I.,I..

wv,.,,JI

/--IowerangeI

")

direction due to a part power calorimetr' assures a reactor trip power range calorimetric heat consistent with the safety analyses. T is allowance does no reclude lbalance calculation making indicated power adjustments, desired, when the alorimetric a'a.':is

-..is less than the channel indicate ower. To provide close agreement between indicated powe ed calorimetric power and to preserve operating margin, the EMhannels are normally adjusted when operating at or near full power during steady-sto power range conditions. However, discretion must be exercised if the

=

jrhannel indicated power is adjusted in the decreasing power direction due to a 1

er-- ran--g part power calorimetric (< 50% RTP). This action could introduce a Power rnon-conservative bias at higher power levels which could result in an u reactor trip above the safety analysis limit (> 118% RTP).

Noutr of Flue High biewtiyebl iaro cois 5

T: )wooo tho e~eq I.

I.

s in The....

in p....

Reactof Tn O tart Pe veore The Powerange Neutr" on Fu4 Hi Th

,._post re.___.,D"* ".,t p I~fr h

ower Range Neutron Flux - High Insert - Bases SR 3.3.1.2 bistables are reset _ 10p% RTP, the NIS channel calibration must be confirmed based on a c lorimetric performed > 50% RTP.

II T

,w Notes m. dfy.,R 3.3.1.2. The first Note, destes that the NIS ohanncl output shel! be adjusted consistent with the eelfrimetrie ealeulated pewer if the eaoezrimetrie ealeulated pewef r meeds the-N46 RhAnnAI A'--R*.:t WO-winr-thain.O 2% RTR. Theam-A 1ma.ndL

,O*t*'rifies th~at this Su eillance is required only if reactor power is > 15%

1 iand that l

J 24 hourtJallowed for performing the first Surveillance after rea 9ing 15% RTP. A power level of 15% RTP is chosen based on plant stability, i.e., automatic rod control capability and turbine generator synchronized to the grid.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.2 is modified by a Note.

IThis Note (continued)

Farley Units 1 and 2 B 3.3.1-51 Revisionfw to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert - Bases SR 3.3.1.2 ITSTF-371 The cause of the potential non-conservative bias is the decreased accuracy of the calorimetric at reduced power conditions. The primary error contributor to the instrument uncertainty for a secondary side power calorimetric measurement is the feedwater flow measurement, which is typically a AP measurement across a feedwater venturi. While the measurement uncertainty remains constant in AP as power decreases, when translated into flow, the uncertainty increases as a square term. Thus a 1% flow error at 100% power can approach a 10% flow error at 30% RTP even though the AP error has not changed. An evaluation of extended operation at part power conditions would conclude that it is prudent to administratively adjust the setpoint of the Power Range Neutron Flux - High bistables to < 85% RTP when: 1) the power range channel output is adjusted in the decreasing power direction due to a part power calorimetric below 50%

RTP; or 2) for a post refueling startup. The evaluation of extended operation at part power conditions would also conclude that the potential need to adjust the indication of the Power Range Neutron Flux in the decreasing power direction is quite small, primarily to address operation in the intermediate range about P-10 (nominally 10%

RTP) to allow enabling of the Power Range Neutron Flux - Low setpoint and the Intermediate Range Neutron Flux reactor trips.

0 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 BASES SURVEILLANCE SR 3.3.1.3 REQUIREMENTS (continued)

SR 3.3.1.3 compares the incore system to the NIS channel output. If the absolute difference is a 3% the NIS channel is still OPERABLE, but it must be adjusted. 90 1 16, Eei;11W !ý-, W;-,=ii-,e

1ot,;et-, % ;-;w rhe excore NIS channel aI.um.d in the cotpoi. t u....t.inty o*...latin, the

.hannel.mu.t be.

shall be adjusted if the e.,,,,,,a',,ed) based e,- i,-.oe su,-e*,,c.-det.

absolute difference between the incore and If the NIS channel cannot be properly adjusted, the channel is declared re i 3inoperable. This Surveillance is performed to periodically verify the excore AFD is >/= 3%.

/

"TSTF-371I f(AI) input to the overtemperature AT Function.

I I

ED-IHERNotes modify SR 31. Note I indicates1 t!ia the exco, e N3I I-*

ON RU

, e AFD) 9* %-. JNot4M, clarifies that the Surveillance is required only if reactor power is >_ 50% RTP and that 7 days are allowed for performing the Surveillance and channel adjustment, if necessary, after reaching 50% RTP. A power level of >_ 50% RTP is consistent with the requirements of SR 3.3.1.9. Note Ilows SR 3.3.1.9 to be performed in lieu of SR 3.3.1.3, since SR3.3.1.9 calibrates (i.e.,

requires channel adjustment) the excore c annels to the incore channels, it envelopes the performance of 3.3.1.3.

2 For each operating cycle, the initial channel normalization is performed under SR 3.3.1.9. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.4 SR 3.3.1.4 is the performance of a TADOT. This test shall verify OPERABILITY by actuation of the end devices.

The RTB test shall include separate verification of the undervoltage trip via the Reactor Protection System and the local manual shunt trip mechanism. The bypass breaker test shall include a local manual shunt trip and local manual undervoltage trip. A Note has been added to indicate that this test must be performed on a bypass breaker prior to placing it in service. The independent test of undervoltage and shunt (continued)

Farley Units 1 and 2 B 3.3.1-52 RevisionFBE to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RTS Instrumentation B 3.3.1 BASES REFERENCES (continued)

17. Westinghouse Technical Bulletin, NSD-TB-92-03-R1, "Undervoltage Trip Protection."

18. WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements," Jan., 1996.

19. WCAP-14036-P-A, Revision 1, "Elimination of Periodic Protection Channel Response Time Tests," Oct., 1998.

20. WCAP 12925, Median Signal Selector (MSS).

21. WCAP 13807/13808, Elimination of Feedwater Flow trip via Implementation of MSS.

22. SNC Calculation E-35.1A & E-35.2A.

I

[TF-355

_J23. Regulatory Guide 1.105, Revision 3, "Setpoints for Safety-Related lInstrumentation."

I Farley Units 1 and 2 B 3.3.1-61 RevisionRel to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages ESFAS Instrumentation B 3.3.2 B 3.3 INSTRUMENTATION B 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation BASES BACKGROUND The ESFAS initiates necessary safety systems, based on the values of selected unit parameters, to protect against violating core design limits and the Reactor Coolant System (RCS) pressure boundary, and to mitigate accidents.

The ESFAS instrumentation is segmented into three distinct but interconnected modules as identified below:

Field transmitters or process sensors and instrumentation:

provide a measurable electronic signal based on the physical characteristics of the parameter being measured;

" Signal processing equipment including analog protection system, field contacts, and protection channel sets: provide signal conditioning, bistable setpoint comparison, process algorithm actuation, compatible electrical signal output to protection system devices, and control board/control room/miscellaneous indications; and Solid State Protection System (SSPS) including input, logic, and output bays: initiates the proper unit shutdown or engineered safety feature (ESF) actuation in accordance with the defined logic and based on the bistable outputs from the signal process control and protection system.

Field Transmitters or Sensors Insert 1 - Bases 3.3.2 Background To meet the design demands for redundancy and reliability, more than one, and in some cases as many as four, field transmitters or sensors are used to measure unit parameters. In many cases, field transmitters or sensors that input to the ESFAS are shared with the L

1 Reactor Trip System (RTS). In some cases, the same channels also provide control system inputs. To account for calibration tolerances and instrument drift, which are assumed to occur between calibrations, statistical allowances are provided in the Trip Setpoint.

The OPERABILITY of each transmitter or senso, ia-i, 51 i;

e,i w

ait UrI "2a inl-i -Rd" nor.fpdt Idoeumented seeeptaftee-eFitef4.

/cniud Insert 2 - Bases 332Background (continued)

Farley Units 1 and 2 B 3.3.2-1 RevisionK]

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert I - Bases 3.3.2 Background The Allowable Value in conjunction with the trip setpoint and LCO establish the threshold for ESFAS action to prevent exceeding acceptable limits such that the consequences of Design Basis Accidents (DBAs) will be acceptable. The Allowable Value-is considered a limiting value such that a channel is OPERABLE if the setpoint is found not to exceed the Allowable Value during the CHANNEL OPERATIONAL TEST (COT). Note that, although a channel is "OPERABLE" under these circumstances, the ESFAS setpoint must be left adjusted to within the established calibration tolerance band of the ESFAS setpoint in accordance with the uncertainty assumptions stated in the referenced setpoint methodology, (as-left criteria) and confirmed to be operating within the statistical allowances of the uncertainty terms assigned.

Insert 2 - Bases 3.3.2 Background ITSTF-355 is determined by either "as-found" calibration data evaluated during the CHANNEL CALIBRATION or by qualitative assessment of field transmitter or sensor, as related to the channel behavior observed during performance of the CHANNEL CHECK.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages ESFAS Instrumentation B 3.3.2 BASES land ESFAS Setpoints ITSTF-355 BACKGROUND Ifl

,;1 howllItdolIowable Values (continued)

Tie Trip 3SepounisL ar the values specifie i the Technical Speeifiesticrne. The Ncminol Trip Getpeint arc the taret values at whieh the field de-Tues aredbst-Wes ae set wothin the a

icallimits bamd, that i3 established em the eenscrwafive aide of the TrFip Sctpoint.

Any proeteetion system ohannels ec pnsiderod to be properly adjuctod when the "as left" value *9 within the bamd fer CHANNEL=

[Fi epit GLIRTO eway trip setpoints TIT ýM~mused are based on the analytica limits red in References 3 and 6. The selection of these S

lis such that adequate protection is provided when all sensor and processing time delays are taken into account. To allow for calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those ESFAS channels that must function in harsh environments as defined by 10 CFR 50.49 (Ref. 7), the *jJ

.Alowable Values specified in Table 3.3.2-1 in the accompanying LCO are e..nscor'Ati*"*ly adjuted It respect to t eonservative analytical limits.

d iii.da"^6"^'t,,

"... ;"he" ""4R i~g use "f^'.....

PcAlcuit the Trip Setpone Hncedin thi ~lctuRewaint~

is Bssprovided in the RT-SiSSFAS Sotpoit Mohdlgy Study (Rotfi )-

ackground Th Ne-minal Trip

--tp

-int and colib

aticn bond aWe mr-" consc.r.tivc thais t 11 at speeifled by the Allowable Value to account fer ehangec in randem meascurcment eFrors deteetoblc by a COT. One example ef cucsh a change inl moeacUreront orror is drift duFrin the curwoillancz

• mterval. If the messured setpeint dees met emeeed the AIlewablc

h te Stpoi m-~o. ang wwt QRAllowable Value ensure that the luirements of the consequences of Design Basis Accidents (DBAs) will be acceptable, providing the unit is operated from within the LCOs at the onset of the DBA and the equipment functions as designed.

Each channel can be tested on line to verify that the signal processing equipment and setpoint accuracy is within the specified allowance requirements. Once a designated channel is taken out of service for testing, a simulated signal is injected in place of or superimposed on the field instrument signal. The process equipment for the channel in test is then tested, verified, and if required, calibrated. SRs for the channels are specified in the SR section.

T-he Thp Getpo;mt; amd Allowable Values listed im Table 3.3.2 4 are based on, OF conservative to, the moethedolegico deseribed-inf Reeene 6, 8, eimd 9, w~hieh ineerperate all of the knownI (continued)

Farley Units 1 and 2 B 3.3.2-3 Revision E_ý'

rlu 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert 3 - Bases 3.3.2 Background A detailed description of the methodology used to calculate the Allowable Value and ESFAS setpoints including their explicit uncertainties, is provided in the plant specific setpoint methodology study (Ref. 6) which incorporates all of the known uncertainties applicable to each channel. The magnitudes of these uncertainties are factored into the determination of each ESFAS setpoint and corresponding Allowable Value. The nominal ESFAS setpoint entered into the bistable is more conservative than that specified by the Allowable Value to account for measurement errors detectable by the COT. The Allowable Value serves as the Technical Specification OPERABILITY limit for the purpose of the COT. One example of such a change in measurement error is drift during the surveillance interval. If the measured setpoint does not exceed the Allowable Value, the bistable is considered OPERABLE.

The ESFAS setpoints are the values at which the bistables are set and is the expected value to be achieved during calibration. The ESFAS setpoint value ensures the safety analysis limits are met for the surveillance interval selected when a channel is adjusted based on stated channel uncertainties. Any bistable is considered to be properly adjusted when the "as-left" setpoint value is within the band for CHANNEL CALIBRATION uncertainty allowance (i.e. calibration tolerance uncertainties). The ESFAS setpoint value is therefore considered a "nominal" value (i.e., expressed as a value without inequalities) for the purposes of the COT and CHANNEL CALIBRATION.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages ESFAS Instrumentation B 3.3.2 BASES n-$-A S point BACKGROUND

-,and Allowable Values 4 continued)

IT" uncert42inties applicable for each channel. The magnitudoc of thocc u uvi tIailifies, factored in1to t' t deteirrnimatien1 ef esh Trip Seltpoint.

All field gemserg emdc signal pr~ein cgupmnt for these ehennels are -ssi 'me-d to oper-te within the a-lol'ncs of these unce*-*_in,'

iiu e

d el* is

.me sttsis -- :--

--e Solid State Protection System The SSPS equipment is used for the decision logic processing of inputs from field contacts and control board switches and the signal processing equipment bistables. To meet the redundancy requirements, two trains of SSPS, each performing the same functions, are provided. If one train is taken out of service for maintenance or test purposes, the second train will provide ESF actuation for the unit. If both trains are taken out of service or placed in test, a reactor trip will result. Each train is packaged in its own cabinet for physical and electrical separation to satisfy separation and independence requirements.

The SSPS performs the decision logic for most ESF equipment actuation; generates the electrical output signals that initiate the required actuation; and provides the status, permissive, and annunciator output signals to the main control room of the unit.

The input signals from field contacts, control board switches and bistable outputs from the signal processing equipment are sensed by the SSPS equipment and combined into logic matrices that represent combinations indicative of various transients. If a required logic matrix combination is completed, the system will send actuation signals via master and slave relays to those components whose aggregate Function best serves to alleviate the condition and restore the unit to a safe condition. Examples are given in the Applicable Safety Analyses, LCO, and Applicability sections of this Bases.

Each SSPS train has a built in testing device that can automatically test the selected decision logic matrix functions and the actuation devices while the unit is at power. When any one train is taken out of service for testing, the other train is capable of providing unit monitoring and protection until the testing has been completed. The testing device is semiautomatic to minimize testing time.

The actuation of ESF components is accomplished through master and slave relays. The SSPS energizes the master relays appropriate (continued)

Farley Units 1 and 2 B 3.3.2-4 R

=

I evision 111ý I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages ESFAS Instrumentation B 3.3.2 BASES BACKGROUND Solid State Protection System (continued) for the condition of the unit. Each master relay then energizes one or more slave relays, which then cause actuation of the end devices.

The master and slave relays are routinely tested to ensure operation.

The test of the master relays energizes the relay, which then operates the contacts and applies a low voltage to the associated slave relays.

The low voltage is not sufficient to actuate the slave relays but only demonstrates signal path continuity. The SLAVE RELAY TEST actuates the devices if their operation will not interfere with continued unit operation. For relays with SLAVE RELAY TEST circuits available actual component operation can be prevented and slave relay contact operation is verified by a continuity check of the circuit containing the slave relay.

APPLICABLE SAFETY ANALYSES, LCO, AND APPLICABILITY Each of the analyzed accidents can be detected by one or more ESFAS Functions. One of the ESFAS Functions is the primary actuation signal for that accident. An ESFAS Function may be the primary actuation signal for more than one type of accident. An ESFAS Function may also be a secondary, or backup, actuation signal for one or more other accidents. For example, Pressurizer Pressure-- Low is a primary actuation signal for small loss of coolant accidents (LOCAs) and a backup actuation signal for steam line breaks (SLBs) outside containment. Functions such as manual initiation, not specifically credited in the accident safety analysis, are qualitatively credited in the safety analysis and the NRC staff approved licensing basis for the unit. These Functions may provide protection for conditions that do not require dynamic transient analysis to demonstrate Function performance. These Functions may also serve as backups to Functions that were credited in the accident analysis. Specific information regarding the ESFAS Functions status as primary or backup actuation signal for a given accident is provided in FSAR Chapter 15 (Ref. 3).

The LCO requires I instrumentation performing an ESFAS Function to be OPERABLE.Typically, failure of any instrument renders the affected channel(s) inoperable and reduces the reliability of the affected Functions.

The LCO generally requires OPERABILITY of two, three or four channels in each instrumentation function and two channels in each (continued)

Farley Units 1 and 2 B 3.3.2-5 Revision =Yj to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert - Bases 3.3.2 ASA A channel is OPERABLE with a trip setpoint value outside its calibration tolerance band provided the trip setpoint "as-found" value does not exceed its associated Allowable Value and provided the trip setpoint "as-left" value is adjusted to a value within the calibration tolerance band of the Nominal Trip Setpoint. A trip setpoint may be set more conservative than the Nominal Trip Setpoint as necessary in response to plant conditions.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages ESFAS Instrumentation B 3.3.2 BASES ACTIONS B.1. B.2.1 and B.2.2 (continued) must be placed in a MODE in which the LCO does not apply. This is done by placing the unit in at least MODE 3 within an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> total time) and in MODE 5 within an additional 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> (84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> total time). The allowable Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

C.1, C.2.!. and C.2.2 Condition C applies to the automatic actuation logic and actuation relays for the following functions:

0 SI; fISTS P 41n aIntrlc Adoption Containment Spray; Phase A Isolation; and 0

Phase B Isolation.

This Condition is intended to address an inoperability of the actuation logic or relays associated with a given train which affects the integrated ESFAS response to an actuation signal. This Condition is applicable whenever more than one ESF system is affected by the inoperable train of logic or relays. However, if one or more inoperable actuation relay(s) in a train affect only a single ESF system, then the ACTIONS Condition of the LCO applicable to the affected ESF component or system should be entered and this Condition is not applicable.

This action addresses the train orientation of the SSPS and the master and slave relays. If one train is inoperable, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> are allowed to restore the train to OPERABLE status. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed for restoring the inoperable train to OPERABLE status is justified in Reference 11. The specified Completion Time is reasonable considering that there is another train OPERABLE, and the low probability of an event occurring during this interval. If the train cannot be restored to OPERABLE status, the unit must be (continued)

Farley Units 1 and 2 B 3.3.2-33 Revision 11W&

I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages ESFAS Instrumentation B 3.3.2 BASES ACTIONS E.1, E.2.1, and E.2.2 (continued)

To avoid the inadvertent actuation of containment spray and Phase B containment isolation, the inoperable channel should not be placed in the tripped condition. Instead it is bypassed. Restoring the channel to OPERABLE status, or placing the inoperable channel in the bypass condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, is sufficient to assure that the Function remains OPERABLE and minimizes the time that the Function may be in a partial trip condition (assuming the inoperable channel has failed high). The Completion Time is further justified based on the low probability of an event occurring during this interval. Failure to restore the inoperable channel to OPERABLE status, or place it in the bypassed condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, requires the unit be placed in MODE 3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 4 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 4, these Functions are no longer required OPERABLE.

The Required Actions are modified by a Note that allows one additional channel to be bypassed for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for surveillance testing.

Placing a second channel in the bypass condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for testing purposes is acceptable based on the results of Reference 11.

ISTS F.1, F.2.1, and F.2.2 land the P-4 interlock Adoption

1. 1 Condition F applies to Manual Initiation of Steam Line Isolation.

land he P-4 Interlock Functions For the Manual Initiation this action addresses the train orientation of the SSPS. If a train or channel is inoperable, 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is allowed to return it to OPERABLE status. The specified Completion Time is reasonable considering the nature of these Functions, the available redundancy, and the low probability of an event occurring during this interval. If the Function cannot be returned to OPERABLE status, the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 4 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power in an orderly manner and without challenging unit systems. In MODE 4, the unit does not have any analyzed transients or conditions that require the explicit use of the protection function noted above.

(continued)

Farley Units 1 and 2 B 3.3.2-36 Revisionrl'i 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Remote Shutdown System B 3.3.4 BASES APPLICABLE The Remote Shutdown System is considered an important contributor SAFETY ANALYSES to the reduction of unit risk to accidents and as such it has been (continued) retained in the Technical Specifications as indicated in 10 CFR 50.36(c)(2)(ii).

LCO The Remote Shutdown System LCO provides the OPERABILITY requirements of the instrumentation and controls necessary to place and maintain the unit in MODE 3 from a location other than the control room. The instrumentation and controls required are listed in Tdbk* 3.3.4-1i i, ti;,

• oi-Aii,.*,;y;iig LOC.

ITable B 3.3.4-1 The controls, instrumentation, and transfer switches (where applicable) are required for:

" Core reactivity control (initial and long term);

RCS pressure control; ITSTF-266 I

" Decay heat removal via the AFW System and SG ARVs;

" RCS inventory control via charging flow; and

• Safety support systems for the above Functions, including service water, component cooling water, and onsite power, including the diesel generators.

Table B 3.3.4-1 A Function of a Remote Shutdown System is OPERABLE if all instrument and control channels needed to support the Remote Shutdown System Function are OPERABLE. However.. n I

trol and transfer circuits in every system identified on

.4-4 are required OPERABLE in order to support the required remote shutdown function. For example, the capability to remotely operate a single AFW pump and associated flow control valve and at least one associated SG atmospheric relief valve support an OPERABLE decay heat removal function. All the control and transfer circuits associated with all three AFW pumps do not have to be OPERABLE to support an OPERABLE decay heat removal function. A remote shutdown function is not inoperable until insufficient control and transfer circuits remain OPERABLE to perform the required function.

(continued)

Farley Units 1 and 2 B 3.3.4-2 Revisionr8ý-

I-,,

I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Remote Shutdown System B 3.3.4 BASES LCO (continued)

The remote shutdown instrument and control circuits covered by this LCO do not need to be energized to be considered OPERABLE. This LCO is intended to ensure the instruments and control circuits will be OPERABLE if unit conditions require that the Remote Shutdown System be placed in operation.

APPLICABILITY The Remote Shutdown System LCO is applicable in MODES 1, 2, and 3. This is required so that the unit can be placed and maintained in MODE 3 for an extended period of time from a location other than the control room.

This LCO is not applicable in MODE 4, 5, or 6. In these MODES, the facility is already subcritical and in a condition of reduced RCS energy. Under these conditions, considerable time is available to restore necessary instrument control functions if control room instruments or controls become unavailable.

ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. Separate Condition entry is allowed for each Functionll-td,-, Ta.`,' 3.3.4 1. The Completion Time(s) of the inoperable channel(s)/train(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.

_.Jthe control and transfer switches forI IT A.1 Ilany required Function.

I

~STF-266]

Conditin A addresses the situation where one or more required Functio,s of the Remote Shutdown System are inoperable. This (cniud H1,.UU~

0 iiy

-IL.U -

o~

land taram 'fer withes,.

j A Remote Shutdown System division is inoperable when each function is not accomplished by at least one designated Remote Shutdown System Channel that satisfies the OPERABILITY criteria for the channel's function. These criteria are outlined in the LCO section of the Bases.

(continued)

Farley Units 1 and 2 B 3.3.4-3 Revision 100-1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Remote Shutdown System B 3.3.4 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.4.3 CHANNEL CALIBRATION is a complete check of the monitoring instrument loop and the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES

1. 10 CFR 50, Appendix A, GDC 19.

ITSTF266I IlNSERT - Bases Table B 3.3.4-1 il Farley Units 1 and 2 B 3.3.4-6 Revision"_-ý riz to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT - Bases Table B 3.3.4-1 Table B 3.3.4-1 (page 1 of 1)

Remote Shutdown System Instrumentation and Controls FUNCTION/INSTRUMENT REQUIRED OR CONTROL PARAMETER NUMBER OF CHANNELS MONITORING INSTRUMENTATION

1. Steam Generator Wide Range Level I /SG

2.

Steam Generator Pressure I /SG

3.

Pressurizer Water Level 1

4.

Pressurizer Pressure 1

5.

RCS Hot Leg Temperature (Loop A) 1

6.

RCS Cold Leg Temperature (Loop A) 1

7.

Source Range Neutron Flux (Gammametrics) 1

8.

Condensate Storage Tank Level 1

TRANSFER AND CONTROL CIRCUITS

9.

Reactivity Control

a. Boric Acid Transfer System

10. RCS Pressure

a. Pressurizer Heater Control

11. RCS Inventory

a. Charging System

b. Letdown Orifice Isolation Valves 1

12. Decay Heat Removal

a. Auxiliary Feedwater System 1

b. SG Atmospheric Relief Valves

13. Safety Grade Support Systems Required For 1

Functions Listed Above to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RCS Minimum Temperature for Criticality B 3.4.2 BASES ACTIONS A. 1 If the parameters that are outside the limit cannot be restored, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to MODE 3 within 30 minutes. Rapid reactor shutdown can be readily and practically achieved within a 30 minute period. The allowed time is reasonable, based on operating experience, to reach MODE 3 in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS JINSERT - SR 3.4.2.1 SR 3.4.2.1 ReS loup aveice tem~perature is required to be ve;fied at orabv 641 *F evenj 30 minutes when the loW loW TdVy alaFrm IS not rocot and aws" Pr.'

Innn T..

!C~ f

ýA 0

~

I-

' dVy I I It~ i'JtJtfl I IItJUIIIfl~ II Ifl flfl WV. 11 p LII IV IA.~I ILflIIIJ flIIrII LIIJfl IflIlItiflI nttAIr J..---.------

TSF27 is 4f1 21-U 1.1= 10-V 10-Y Iavg 3121l1l1 IS didlI 1111 lJ, rVtO iU00P dvuIdyu tcmpefraturz3f eetuld fall below the LCO) requirement without additionali ThI ieR to verify RCC 'cop avefege tempzraturzs every 30 _Minu~tes is frcglucnt eneugh to prcvent the ino&.zrtcnt vielatien ef the i~eG.

REFERENCES

1. FSAR, Section 4.3 and 15.

Farley Units 1 and 2 B 3.4.2-3 Revision[5:1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT - SR 3.4.2.1 Bases ITSTF-27 I RCS loop average temperature is required to be periodically verified at or above 541'F. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RCS Loops - MODE 3 B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.5 RCS Loops -MODE 3 BASES BACKGROUND In MODE 3, the primary function of the reactor coolant is removal of decay heat and transfer of this heat, via the steam generator (SG), to the secondary plant fluid. The secondary function of the reactor coolant is to act as a carrier for soluble neutron poison, boric acid.

The reactor coolant is circulated through three RCS loops, connected in parallel to the reactor vessel, each containing an SG, a reactor coolant pump (RCP), and appropriate flow, pressure, level, and temperature instrumentation for control, protection, and indication.

The reactor vessel contains the clad fuel. The SGs provide the heat sink. The RCPs circulate the water through the reactor vessel and SGs at a sufficient rate to ensure proper heat transfer and prevent fuel damage.

In MODE 3, RCPs are used to provide forced circulation for heat removal during heatup and cooldown. The MODE 3 decay heat removal requirements are low enough that a single RCS loop with one RCP running is sufficient to remove core decay heat. However, two RCS loops are required to be OPERABLE to ensure redundant capability for decay heat removal.

APPLICABLE SAFETY ANALYSES Whenever the reactor trip breakers (RTBs) are in the closed position and the control rod drive mechanisms (CRDMs) are energized, an inadvertent rod withdrawal from subcritical, resulting in a power excursion, is possible. Such a transient could be caused by a malfunction of the rod control system. In addition, the possibility of a power excursion due to the ejection of an inserted control rod is possible with the breakers closed or open. Such a transient could be caused by the mechanical failure of a CRDM.

ITSTF_87 Therefore, in MODE 3 with F;Ui, m the..........

• '....l.

Rod Control System capable of rod withdrawal, accidental control rod withdrawal from subcritical is postulated and requires at least two RCS loops to be OPERABLE and in operation to ensure that the accident analyses limits are met. For those conditions when the Rod Control System is not capable of rod withdrawal, two RCS loops are (continued)

Farley Units 1 and 2 B 3.4.5-1 RevisionF]

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RCS Loops - MODE 3 B 3.4.5 BASES APPLICABLE SAFETY ANALYSES (continued) required to be OPERABLE, but only one RCS loop is required to be in operation to be consistent with MODE 3 accident analyses.

Failure to provide decay heat removal may result in challenges to a fission product barrier. The RCS loops are part of the primary success path that functions or actuates to prevent or mitigate a Design Basis Accident or transient that either assumes the failure of, or presents a challenge to, the integrity of a fission product barrier.

RCS Loops -MODE 3 satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The purpose of this LCO is to require that at least two RCS loops be OPERABLE. In MODE 3 with the JRTs in t-e closed positi.

and I Rod Control System capable of rod withdrawal, two OPERABLE RCS loops must be in operation. Two OPERABLE RCS loops are required to be in operation in MODE 3 with Rod Control System capable of rod withdrawal due to the postulation of a power I excursion because of an inadvertent control rod withdrawal. The required number of RCS loops in operation ensures that the Safety Limit criteria will be met for all of the postulated accidents.

~87 r--ýWhen

_V I

IVVIII j

LII

_ IT I J1 III TIIIC UIJII J.UOIUIYI, VI LIIV '.,rXL./IViC)

IUl Rod Control System is not capable of rod withdrawal only one OPERABLE RCS loop in operation is necessary to ensure removal of decay heat from the core and homogenous boron concentration throughout the RCS. An additional RCS loop is required to be OPERABLE to ensure that safety analyses limits are met.

The Note permits all RCPs to not be in operation for _ 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> per 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> period. The purpose of the Note is to perform tests that are designed to validate various accident analyses values. One of these tests is validation of the pump coastdown curve used as input to a number of accident analyses including a loss of flow accident. This test is generally performed in MODE 3 during the initial startup testing program, and as such should only be performed once. If, however, changes are made to the RCS that would cause a change to the flow characteristics of the RCS, the input values of the coastdown curve must be revalidated by conducting the test again. Another test performed during the startup testing program is the validation of rod drop times during cold conditions, both with and without flow.

(continued)

Farley Units 1 and 2 B 3.4.5-2 Revisiorff]

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RCS Loops - MODE 3 B 3.4.5 BASES APPLICABILITY (continued)

Operation in other MODES is covered by:

LCO 3.4.4, "RCS Loops -MODES 1 and 2";

LCO 3.4.6, "RCS Loops -MODE 4";

LCO 3.4.7, "RCS Loops -MODE 5, Loops Filled";

LCO 3.4.8, "RCS Loops -MODE 5, Loops Not Filled";

LCO 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation -High Water Level" (MODE 6); and LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level" (MODE 6).

ACTIONS A._1 If one required RCS loop is inoperable, redundancy for heat removal is lost. The Required Action is restoration of the required RCS loop to OPERABLE status within the Completion Time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. This time allowance is a justified period to be without the redundant, nonoperating loop because a single loop in operation has a heat transfer capability greater than that needed to remove the decay heat produced in the reactor core and because of the low probability of a failure in the remaining loop occurring during this period.

B._1 If restoration is not possible within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, the unit must be brought to MODE 4. In MODE 4, the unit may be placed on the Residual Heat Removal System. The additional Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is compatible with required operations to achieve cooldown and depressurization from the existing plant conditions in an orderly manner and without challenging plant systems.

place the Rod Control System in a condition incapable of rod withdrawal (e.g.,

C.1 and C.2 If the required RCS IoopJ0 not in operation, and the RT-a-mr-el *ka

,L__od Control System capable of rod withdrawal, the Required Action is either to restore the required RCS loop to operation or to ITSTF'87 I J'

de-energize all CRDMs by opening the RTBs or de-energizing the motor generator (MG) sets When the N ii!

P,

[

Rod Control Syste able of rod withdrawal, it is postulated that a power excursion ul occur in the event of an is (continued)

Farley Units 1 and 2 B 3.4.5-4 Revisionwi to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RCS Loops - MODE 3 B 3.4.5 BASES ACTIONS C.1 and C.2 (continued)

Rod Control System must be rendered incapable of rod withdrawal place the Rod Control System in a condition incapable of rod withdrawal (e.g.,

inadvertent control rod withdrawal. This mandates having the heat transfer capacity of two RCS loops in operation. If only one loop is in operation, thefRTB* n~uht bl uUt,,;d.

The Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to restore the required RCS loop to operation or e-W CR 4's adequate to perform these operations in an orderly manner wit ut exposing the unit to risk for an undue time period.

defeat the Rod Control System D.1. D.2, and D.3 If two required CS loops are i operable or no RCS loop is in operation, excet as during c ditions permitted by the Note in the LCO section, al CRDMs mu be de-energized by opening the RTBs or de-energizing the MG sets. All operations involving a reduction of RCS boron concentration must be suspended, and action to restore one of the RCS loops to OPERABLE status and operation must be initiated. Boron dilution requires forced circulation for proper mixing, and opening the RTBs or de-energizing the MG sets removes the possibility of an inadvertent rod withdrawal. The immediate Completion Time reflects the importance of maintaining operation for heat removal. The action to restore must be continued until one loop is restored to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS SR 3.4.5.1 This SR requires verification that the required loops are in operation.

Verification includes flow rate, temperature, and pump status monitoring, which help ensure that forced flow is providing heat removal. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.4.5.2 SR 3.4.5.2 requires verification of SG OPERABILITY. SG OPERABILITY is verified by ensuring that the secondary side narrow range water level is > 30% for required RCS loops. If the SG (continued)

Farley Units 1 and 2 B 3.4.5-5 Revisionp]

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Pressurizer B 3.4.9 BASES APPLICABILITY The need for pressure control is most pertinent when core heat can cause the greatest effect on RCS temperature, resulting in the greatest effect on pressurizer level and RCS pressure control. Thus, applicability has been designated for MODES 1 and 2. The applicability is also provided for MODE 3. The purpose is to prevent solid water RCS operation during heatup and cooldown to avoid rapid pressure rises caused by normal operational perturbation, such as reactor coolant pump startup.

A Note has been added to indicate the limit on pressurizer level is not applicable during short term operational transients such as a THERMAL POWER ramp > 5% RTP per minute or a THERMAL POWER step > 10% RTP. These conditions represent short term perturbations.

In MODES 1, 2, and 3, there is need to maintain the availability of pressurizer heaters, capable of being powered from an emergency power supply. In the event of a loss of offsite power, the initial conditions of these MODES give the greatest demand for maintaining the RCS in a hot pressurized condition with loop subcooling for an extended period. For MODE 4, 5, or 6, it is not necessary to control pressure (by heaters) to ensure loop subcooling for heat transfer when the Residual Heat Removal (RHR) System is in service, and therefore, the LCO is not applicable.

f,

.A.!,A.2A3 and A.4 ACTIONS IA., I d A.2*

all rods fully inserted and incapable of withdrawal.

Additionally, the unit must be brought Pressurizer water level control malfunctions or other plant evolutions may result in a pressurizer water level above the nominal upper limit, even with the plant at steady state conditions.

within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> If the pressurizer water lev I is not within the limit, wh the limit is TSTF-87 applicable, action must be taken to bring the plant to ODE in s

I which the LCO does not a ply. To achieve this status, the unit must be b ro uht to MODE 3, with,-e f -- et 8rFt,.,p b,,8,mmaW p V0,

,tr

-h~ur~nto MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. This takes the unit out of the applicable MODES.

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

(continued)

Farley Units 1 and 2 B 3.4.9-3 Revisionlý:i to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Pressurizer PORVs B 3.4.11 BASES APPLICABILITY valves or an RCS vent of >_ 2.85 inches squared is used for (continued) overpressure protection in MODES 4, 5, and 6 with the reactor vessel head in place. LCO 3.4.12 addresses the overpressure protection

'STF-2477 requirements in these MODES.

[2 land block valves ACTIONS A Note has been added to clarify that all pressurizer PORVs are treated as separate entities, each with separate Completion Times (i.e., the Completion Time is on a component basis).

A.1 With the PORVs inoperable and capable of being manually cycled, either the PORVs must be restored or the flow path isolated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The block valves should be closed but power must be maintained to the associated block valves, since removal of power would render the block valve inoperable. Although a PORV may be designated inoperable, it may be able to be manually opened and closed, and therefore, able to perform its function. PORV inoperability may be due to seat leakage, instrumentation problems related to remote manual operation of the PORVs, or other causes that do not prevent manual use and do not create a possibility for a small break LOCA. For these reasons, the block valve may be closed but the Action requires power be maintained to the valve. This Condition is only intended to permit operation of the plant for a limited period of time not to exceed the next refueling outage (MODE 6) so that maintenance can be performed on the PORVs to eliminate the problem condition.

Quick access to the PORV for pressure control can be made when power remains on the closed block valve. The Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is based on plant operating experience that has shown that minor problems can be corrected or closure accomplished in this time period.

(continued)

Farley Units 1 and 2 B 3.4.11-4 Revision =2 r 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Pressurizer PORVs B 3.4.11 BASES ACTIONS D.1 and D.2 (continued)

If the Required Action of Condition A, B, or C is not met, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODES 4, 5, and 6, the PORVs are not required OPERABLE.

E.1, E.2, E.3, and E.4 If more than one PORV is inoperable and not capable of being manually cycled, it is necessary to either restore at least one valve within the Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or isolate the flow path by closing and removing the power to the associated block valves. The Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is reasonable, based on the small potential for challenges to the system during this time and provides the operator time to correct the situation. If one PORV is restored and one PORV remains inoperable, then the plant will be in Condition B with the time clock started at the original declaration of having two PORVs inoperable. If no PORVs are restored within the Completion Time, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODES 4, 5, and 6, the PORVs are not required OPERABLE.

F.11 F-/--dt~-1two block valves are

-8AITSTF-247 i'*,',"a he a," see's-ed P-RY9 em m',.;;

i,,-;**-I'een,.:; '

_1, Ire'st'oreat le'as-t one block valve within 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />sla~_nd 8F the'*.?

Fe,, m a,"n--;,.,.

ble.ek we':-ve ivFt~hir, _2,h&WIT The Completion asonable, based on the small potential for challenges to the system dl)ýýng this time and provide the operator time to correct the situation. _Time is (continued)

Farley Units 1 and 2 B 3.4.11-6 Revision=IF117-1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Pressurizer PORVs B 3.4.11 BASES ACTIONS G.1 and G.2 (continued)

If the Required Actions of Condition F are not met, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. In MODES 4, 5, and 6, the PORVs are not required OPERABLE.

SURVEILLANCE SR 3.4.11.1 REQUIREMENTS Block valve cycling verifies that the valve(s) can be closed if needed.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.FFh bl" e valv a"s" tieate a,

Ion tht.

H181-es pable ef being menu l~y eyeled, the OPE=RABILIT-Y oe the bItk valve 6; of ;mpoite, te, beecause epemimg the Weeck Valve is a.. to pef...it thc P.R. t. be used for mAnual oontrol of i eaeto1 pressure. if the Weeck valve me elesed to iselate an etherwise

• nopefrble PORY, the maximumn Completien Time te restere the PeRY 9ad open the bleek vako is 72 heurc. Furthfhormor, theso tost

• cquirememts would be eemplcted by the roopening 6f a Fe3Ontly (I~

Wleek vav apanu estmaption of the PERV to OPERABLE sttu (ie, eemplet ie*' ef tIhe. Reeluffrd Aetions fulfills the GR).

This SR is modified by two Notes. Note 1 modifies this SR by stating that it is not required to be 1with the block valve closecln accordance with the Reqed of this LCO. Note 2 modifies this SR to allow entry nti and operat on in MODE 3 prior to performing the SR. Thi allows the t t to be performed in MODE 3 under operating tempjerture c~onditio s, prior to entering MODE 1 or

2.

V

2.

perormedActions In accordance with Reference 3, administrative controls require this test to be performed in MODE 3 or 4 to adequately simulate opening temperature and pressure effects on PORV operation.

(continued)

Farley Units 1 and 2 B 3.4.11-7 RevisionF1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Pressurizer PORVs B 3.4.11 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.11.2 SR 3.4.11.2 requires a complete cycle of each PORV in MODE 3 or 4.

The PORVs are stroke tested during MODES 3 or 4 with the associated block valves closed in order to limit the uncertainty introduced by testing the PORVs at lesser system temperatures than expected during actual operating conditions. Operating a PORV through one complete cycle ensures that the PORV can be manually actuated for mitigation of an SGTR. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Note modifies this SR to allow entry into and operation in MODE 3 prior to performing the SR. This allows the test to be performed in MODE 3 under operating temperature conditions, prior to entering MODE 1 or 2.

SR 3.4.11.3 SR 3.4.11.3 requires a complete cycle of each PORV using the backup PORV control system. This surveillance verifies the capability to operate the PORVs using the backup nitrogen supply system.

Additionally, this surveillance ensures the correct function of the associated nitrogen supply system valves. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

II REFERENCES

1. Regulatory Guide 1.32, February 1977.

2. FSAR Sections 5.5 and 15.2.

\\

_3. Generic Letter 90-06, "Resolution of Generic Issue 70, 'Power-Operated Relief Valve and Block Valve Reliability,' and Generic Issue 94, 'Additional Low-Temperature Overpressure Protection for Light-Water Reactors,' Pursuant to 10 CFR 50.54(f)," June 25, 1990.

Farley Units 1 and 2 B 3.4.11-8 Revision ffl to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages LTOP System B 3.4.12 BASES SURVEILLANCE SR 3.4.12.1. SR 3.4.12.2. and SR 3.4.12.3 (continued)

REQUIREMENTS pump start such that a single failure or single action will not result in an injection into the RCS. This may be accomplished through the Hot Shutdown Panel Local/Remote and pump control switches being placed in the Local and Stop positions, respectively, and at least one valve in the discharge flow path being closed with the position of these components controlled administratively.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.4.12.4 Each required RHR suction relief valve shall be demonstrated OPERABLE by verifying its RHR suction isolation valves (8701A, 8701 B, 8702A and 8702B) are open. This Surveillance is only required to be performed if the RHR suction relief valve is being used to meet this LCO.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.4.12.5 The RCS vent of >_ 2.85 square inches is proven OPERABLE by verifying its open condition.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The passive vent arrangement must only be open to be OPERABLE.

TSTF-284 This Surveillance is required to b if the vent is being used I I

to satisfy the pressure relief req*ements of the LCO 3.4.12b.

SR 3.4.12.6 The RHR relief valves are verified OPERABLE by testing the relief setpoint. The setpoint verification ensures proper relief valve mechanical motion as well as verifying the setpoint. Testing is performed in accordance with the Inservice Testing Program which is based on the requirements of the ASME Code, Section Xl (Ref. 7).

(continued)

Farley Units 1 and 2 B 3.4.12-11 Revision 91 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages ECCS - Operating B 3.5.2 BASES ACTIONS A..1 With one or more trains inoperable and at least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available, the inoperable components must be returned to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is based on an NRC reliability evaluation (Ref. 5) and is a reasonable time for repair of many ECCS components.

An ECCS train is inoperable if it is not capable of delivering design flow to the RCS. Individual components are inoperable if they are not capable of performing their design function or supporting systems are not available.

The LCO requires the OPERABILITY of a number of independent subsystems. Due to the redundancy of trains and the diversity of subsystems, the inoperability of one component in a train does not render the ECCS incapable of performing its function. Neither does fTT-325 the inoperability of two different components, each in a different train, necessarily result in a loss of function for the ECCS. Th rctft',

of the EG

, flo........

itt a

-n'n^n

-A r-,-,r b~t,;&

,*,,,,°.....

v°,°,.'L, IThis allows increased flexibility in plant operations under circumstances when components in opposite trains are inoperable.

An event accompanied by a loss of offsite power and the failure of an EDG can disable one ECCS train until power is restored. A reliability analysis (Ref. 5) has shown that the impact of having one full ECCS train inoperable is sufficiently small to justify continued operation for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Reference 6 describes situations in which one component, such as an RHR crossover valve, can disable both ECCS trains. With one or more component(s) inoperable such that 100% of the flow equivalent to a single OPERABLE ECCS train is not available, the facility is in a condition outside the accident analysis. Therefore, LCO 3.0.3 must be immediately entered.

(continued)

Farley Units 1 and 2 B 3.5.2-7 RevisionfFý to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES ECCS - Operating B 3.5.2 ACTIONS (continued)

Insert - Bases 3.5.2 B.1 and B.2 If the inoperable trains cannot be returned to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 4 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

ITSTF-325 SURVEILLANCE REQUIREMENTS SR 3.5.2.1 Verification of proper valve position ensures that the flow path from the ECCS pumps to the RCS is maintained. Misalignment of these valves could render both ECCS trains inoperable. Securing these valves in position by removal of power by locking open the disconnect device to the valve operators ensures that they cannot change position as a result of an active failure or be inadvertently misaligned.

These valves are of REQUIREMENTS the type, described in Reference 6, that can disable the function of both ECCS trains and invalidate the accident analyses. SR 3.5.2.1 is modified by a Note that specifies when this SR is applicable to valves 8132 A/B. Valves 8132 A/B only have the potential to disable both ECCS trains when centrifugal charging pump "A" is inoperable. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.5.2.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve will automatically reposition within the proper stroke time. This Surveillance does not require any testing or valve manipulation.

Rather, it involves verification that those valves capable of being (continued)

Farley Units 1 and 2 B 3.5.2-8 r=

Revisionluz 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert - Bases 3.6.2 CA_

Condition A is applicable with one or more trains inoperable. The allowed Completion Time is based on the assumption that at least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train is available. With less than 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available, the facility is in a condition outside of the accident analysis. Therefore, LCO 3.0.3 must be entered immediately.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES Seal Injection Flow B 3.5.5 ACTIONS A. 1 Vogtle A.81 8

Change #1 With the seal injction flow exceeding its limit, the amount of charging flow available t the RCS may be reduced. Under this Condition, action must b aken to restore the flow to below its limit. The operator has 4L ours from the time the flow is known to be above the limit to perform SR 3.5.5.1 and correctly position the manual valves and thus be in compliance with the accident analysis. The Completion Time minimizes the potential exposure of the plant 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 on operating experience and is sufficient for taking corrective actions by operations personnel.

B.1 and B.2 When the Required Actions cannot be completed within the required Completion Time, a controlled shutdown must be initiated. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for reaching MODE 3 from MODE 1 is a 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 shutdown begun in Required Action B.1, an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is a reasonable time, based on operating experience and normal cooldown rates, to reach MODE 4, where this LCO is no longer applicable.

SURVEILLANCE REQUIREMENTS SR 3.5.5.1 Verification that the manual seal injection throttle valves are adjusted to give a flow within the limits (operation in the acceptable region of Figure 3.5.5-1) ensures that proper manual seal injection throttle valve position, and hence, proper seal injection flow, is maintained. A differential pressure that is above the reference minimum value is established between the charging header (PT-121, charging header pressure) and the pressurizer, and the total seal injection flow is verified to be within the limits determined in accordance with the ECCS safety analysis. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

(continued)

Farley Units 1 and 2 B 3.5.5-3 Revisionr'--'

IUZ I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES Seal Injection Flow B 3.5.5 SURVEILLANCE 8 SR 3.5.5.1 (continued)

Cage REQUIREMENTS

\\,RTs noted, the Surveillance is not required to be performed until hours after the RCS pressure has stabilized within a +/- 20 psig range of normal operating pressure. The RCS pressure requirement is specified since this configuration will produce the required pressure conditions necessary to assure that the manual valves are set correctly. The exception is limited to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to ensure that the Surveillance is timely.

REFERENCES

1. FSAR, Chapter 6 and Chapter 15.

2.

10 CFR 50.46.

Farley Units 1 and 2 B 3.5.5-4 RevisionE to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Containment B 3.6.1 BASES I

ACTIONS (continued)

B.1 In the event containment is inoperable for reasons other than Condition A, containment must be restored to OPERABLE status within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining containment during MODES 1, 2, 3, and 4. This time period also ensures that the probability of an accident (requiring containment OPERABILITY) occurring during periods when containment is inoperable is minimal.

C.1 and C.2 If containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SR 3.6.1.1 Insert-Bases SR 3.6.1.1 Maintaining the containment OPERABLE require compliance with the visual examinations and leakage rate test r uirements of the Containment Leakage Rate Testing Program.

ailure to meet air lock and purge valve with resilient seal leakage limits specified in LCO 3.6.2 and LCO 3.6.3 does not invalidate the acceptability of these overall leakage determinations unless their contribution to overall Type A, B, and C leakage causes that to exceed limits. As left leakage prior to the first startup after performing a required Containment Leakage Rate Testing Program leakage test is required to be !5 0.6 L, for combined Type B and C leakage, and

< 0.75 La for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of < 1.0 La. At < 1.0 L, the offsite dose consequences are bounded by the assumptions of the safety analysis.

SR Frequencies are as required by the Containment Leakage Rate Testing Program. These periodic testing requirements verify that the containment leakage rate does not exceed the leakage rate assumed in the safety analysis.

(continued)

Farley Units 1 and 2 B 3.6.1-4 RevisionFF]

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT - BASES SR 3.6.1.1 The containment concrete visual examinations may be performed during either power operation, e.g., performed concurrently with other containment inspection-related activities such as tendon testing, or during a maintenance or refueling outage. The visual examinations of the steel liner plate inside containment are performed during maintenance or refueling outages since this is the only time the liner plate is fully accessible.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.3.3 This SR requires verification that each containment isolation manual valve and blind flange located inside containment and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the containment boundary is within design limits. For containment isolation valves inside containment, the Frequency of "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is appropriate since these containment isolation valves are operated under administrative controls and the probability of their misalignment is low.

The SR specifies that containment isolation valves that are open under administrative controls are not required to meet the SR during the time they are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Note 1 allows valves and blind flanges located in high radiation areas to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, 3, and 4, for ALARA reasons. Therefore, the probability of misalignment of these containment isolation valves, once they have been verified to be in their proper position, is small. Note 2 provides an allowance to only verify the blind flange on the fuel transfer canal flange after each draining of the canal.

SR 3.6.3.4 power operated Verifying that the isolation time of each *,uw t

,pm automatic 61 containment isolation valve in the IST Program is within limits is required to demonstrate OPERABILITY. The isolation time test ensures the valve will isolate in a time period less than or equal to that assumed in the safety analyses. The isolation time and Frequency of this SR are in accordance with the Inservice Testing Program.

Any change in the components being tested by this SR will require reevaluation of STI Evaluation Number 558904 in accordance with the Surveillance Frequency Control Program.

(continued)

Farley Units I and 2 B 3.6.3-12 Revision=1 1117ý1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES Containment Spray and Cooling Systems B 3.6.6 APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment and an increase in containment pressure and temperature requiring the operation of the containment spray trains and containment cooling trains.

In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Thus, the Containment Spray System and the Containment Cooling System are not required to be OPERABLE in MODES 5 and 6.

ACTIONS A._1 With one containment spray train inoperable, the inoperable containment spray train must be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In this Condition, the remaining OPERABLE spray and cooling trains are adequate to perform the iodine removal and containment cooling functions. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the redundant heat removal capability afforded by the Containment Spray System, reasonable time for repairs, and low probability of a DBA occurring during this period.

The, 13 day poto of the eampl et1 io Time for Requi.red Aetier1 AA1 is based upun ungiiiin uyitiL It takesito accun th.UII e low probability ef eeineidEn cnt; ino woCnd-itions in this Specification eetupled with the low prbblt fan accident occurring during thes time. Refer tu SeCtIon i.3, "Comtpletioni Tl1Iiue" falit~ inuie detailed diseussien ef the purpose o~f the "fre,, isovr of ~failae to, i it 1:

L~e0" puitiui o[ tile Comrpletionu Tillie.

B.1 and B.2 If the inoperable containment spray train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 5 within 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br />. The allowed Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. The extended interval (continued)

Farley Units 1 and 2 B 3.6.6-6 Revision=r1U_ I I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Containment Spray and Cooling Systems B 3.6.6 BASES ACTIONS B.1 and B.2 (continued) to reach MODE 5 allows additional time for attempting restoration of the containment spray train and is reasonable when considering the driving force for a release of radioactive material from the Reactor Coolant System is reduced in MODE 3.

C._ 1 With one of the required containment cooling trains inoperable, the inoperable required containment cooling train must be restored to OPERABLE status within 7 days. The components in this degraded condition provide iodine removal capabilities and are capable of providing at least 100% of the heat removal needs. The 7 day Completion Time was developed taking into account the redundant heat removal capabilities afforded by combinations of the Containment Spray System and Containment Cooling System and the low probability of DBA occurring during this period.

TSTF-439 ThIS 0 day puaii, uf t1:

C 1,,,,pet;ion T i te o,% Requi*ed Actia C.1 i based upon cng rinjudgm,,t. it takes i asucount the lo.

p.J I

"gtlJ ly of Ul idei it e ity u Lvvu tw U iditiu.

l I

I in

.hi SpecldIUI I coupled wit! ieI low pi obabflity of 9. 1 eaffden t zcurring duidng thi3 time. Refer to. Ceeztii 1.3 fi. a.i i to, detailed dibIcubbicii io h~

purpose of the "from dicoo~er; of fai!urz to mzcet the LCO" portion ef the C.mpltion Tirm.

D.1 With two required containment cooling trains inoperable, one of the required containment cooling trains must be restored to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The components in this degraded condition provide iodine removal capabilities and are capable of providing at least 100% of the heat removal needs after an accident. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time was developed taking into account the redundant heat removal capabilities afforded by combinations of the Containment Spray System and Containment Cooling System, the iodine removal function of the Containment Spray System, and the low probability of DBA occurring during this period.

(continued)

Farley Units 1 and 2 B 3.6.6-7 Revision=n M I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages AFW System B 3.7.5 BASES LCO (continued) generators are OPERABLE. This requires that the two motor-driven AFW pump trains be OPERABLE with one shared flow path, each supplying AFW to all steam generators. In addition, the turbine driven AFW pump train is required to be OPERABLE with redundant steam supplies from each of two main steam lines upstream of the MSIVs, and shall be capable of supplying AFW to any of the steam generators via its associated flow path. The control room manual actuation switches for each AFW pump shall also be OPERABLE.

The piping, valves, instrumentation, and controls in the required flow paths also are required to be OPERABLE. A flow path is operable when it is capable of supporting the required AFW flow.

APPLICABILITY In MODES 1, 2, and 3, the AFW System is required to be OPERABLE in the event that it is called upon to function when the MFW is lost. In addition, the AFW System is required to supply enough makeup water to replace the steam generator secondary inventory, lost as the unit cools to MODE 4 conditions.

In MODE 4 the AFW System may be used for heat removal via the steam generators. However, the OPERABILITY of the AFW system in MODE 4 is not assumed in the safety analysis and this LCO does not require the AFW system OPERABLE in MODE 4.

In MODE 5 or 6, the steam generators are not normally used for heat removal, and the AFW System is not required.

ACTIONS A Note prohibits the application of LCO 3.0.4b to an inoperable AFW train. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an AFW train inoperable and the provisions of LCO 3.0.4b, which allow entry into a MODE or other specified 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.

or if turbine driven pump is inoperable while in MODE A.1 3 immediately following refueling, If one of thV o steam supplies to the turbine driven AFW train is inoperable, action must be taken to restor OPERABLE status within T-STF-34 7 days. The 7 day Completion Time is re onable, based on the following reasons:

. /

Ithe inoperable equipment to an (continued)

Farley Units I and 2 B 3.7.5-5 Revision =

TC117 I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES AFW System B 3.7.5 ACTIONS INSERT 1 - TS 3.7.5 Bases Action A A.1 (continued)

2. The radundant OPEmRABLE S steam supply to the turbine driyen AFW pump,

b. The a.ailability of rzunda^t OPERABLE meter,, di AAF pumps and-

&The low prob9ability of an eyent occurring@ that requireg h inoperable steam cupply to the turbine drivon AFW pumrp.

The seconid ompletio-1 Time for Required Action A.14 establishesa limi~t on the m~aximumn time allowed for anY comAbina2tion of Conditions tu be iioupe, able du, iiy a,Iy couiiuuus f'aiuae tou,,eet t-,t LCG*

The 10 day Completion Time pr.vide1 a limit;tien time allowed in this specified Condition after disc*,*ry of failure to meet the LCO. This lii i o isiudei, ed, eso, ble Fo, antuations r1 which Conditions A and B aro entered concIurrently. The AND connecter hbpeF.on 7! days INSERT 2 - TS 3.7.5 a d1 asdcae hat -oth CompletionTmcapl B1ases Action A simultaneously, and te mRore restrGictVe mus1t _be met.

B. 1 With one of the required AFW trains (pump or flow path) inoperable for reasons other than Condition A, action must be taken to restore OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. A flow path is inoperable if it is blocked such that the required AFW flow cannot be delivered. This Condition includes the loss of two steam supply lines to the turbine driven AFW pump. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time is reasonable, based on redundant capabilities afforded by the AFW System, time needed for repairs, and the low probability of a DBA occurring during this time period.

The secod Conpletiom Time for Required Actien 0.1 establishes limit en the a.iu. ti-m allowed for an comb,,inati, of CG,,,dit,.

to be *neperable durnng emy continuous failure to meet this LO Thel10iday Cmpletin Time p*roides a limitation timel allowed in this apeeiffied Condition after diseevery of failure to meet the LCO). This i,,ii j f; is cu, idei, ed easuiiable fo-rtut,-

is,,"i wH Codeom ms A

=n R are entered r-oG=L'rrestly. The AND Connc*tor bhobeo

-2,

iouu

... d 10 days di-tat that beth Complet.Ion Timeis appi simutirlsno'..sly, and the more rectrictive must be mret.

(continued)

Farley Units 1 and 2 B 3.7.5-6 Revision R]

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert - TS 3.7.5 Bases Action A Insert 1

a. For the inoperability of a steam supply to the turbine driven AFW pump, the 7 day Completion time is reasonable since there is a redundant steam supply line for the turbine driven pump.

b. For the inoperability of a turbine driven AFW pump while in MODE 3 immediately subsequent to a refueling, the 7 day Completion time is reasonable due to the minimal decay heat levels in this situation.

c. For both the inoperability of a steam supply line to the turbine driven pump and an inoperable turbine driven AFW pump while in MODE 3 immediately following a refueling, the 7 day Completion time is reasonable due to the availability of redundant OPERABLE motor driven AFW pumps; and due to the low probability of an event requiring the use of the turbine driven AFW pump.

Insert 2 Condition A is modified by a Note which limits the applicability of the Condition to when the unit has not entered MODE 2 following a refueling. Condition A allows one AFW train to be inoperable for 7 days vice the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time in Condition B. This longer Completion Time is based on the reduced decay heat following refueling and prior to the reactor being critical.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages AFW System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.1 (continued)

FT REQUIREMENTS T-

• urveivllaiice is modified by a Note th~at provides an emeeptien f3; UIV MF VV IUW L.ELIU i U VW*V~.

i=

VII V~IMIUIlaUI Vi

=I VV IVV t~UuI1I valves in the full open position is not roguirod during low pow@r Ve peratien (:g 10%4 RTP) er when the AFW system Is noet on autermatic ponterol1. The system is poncidered in autematic oontrOl when it icn II INSERT - BASES SR 3.7.5.1 Note J

standby for A6FW aAmalnxftic inifiation andi not being operatord mBAnUSll.

The pr8;'i9o3 of thiS note allow eperltiOn sauh as porm8' unit stafp orF hutd"wn and Uir-- d AFW pump testing a" powcr to be peorformd withetut vieletimg the reoqutirements ef this GR.

In addition, this surveillance includes verification that the stop check valves 3350A, 3350B, and 3350C are in the open position with the breaker to the valve operators locked open.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.5.2 Verifying that each AFW pump's developed head at the flow test point is greater than or equal to the required developed head ensures that AFW pump performance has not degraded during the cycle. Flow and differential head are normal tests of centrigufal pump performance required by Section XI of the ASME Code (Ref 2). This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. Performance of inservice testing discussed in the ASME Code, Section Xl (Ref. 2) (only required at 3 month intervals) satisfies this requirement. Any change in the components being tested by this SR will require reevaluation of STI Evaluation Number 558904 in accordance with the Surveillance Frequency Control Program.

This SR is modified by a Note indicating that the SR should be deferred until suitable test conditions are established. This deferral is required because there is insufficient steam pressure to perform the test.

(continued)

Farley Units 1 and 2 B 3.7.5-8 RevisionEm""

P71 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT-Bases SR 3.7.5.1 Note The SR is modified by a Note that states one or more AFW trains may be considered OPERABLE during alignment and operation for steam generator level control, if it is capable of being manually (i.e., remotely or locally, as appropriate) realigned to the AFW mode of operation, provided it is not otherwise inoperable. This exception allows the system to be out of its normal standby alignment and temporarily incapable of automatic initiation without declaring the train(s) inoperable. Since AFW may be used during startup, shutdown, hot standby operations, and hot shutdown operations for steam generator level control, and these manual operations are an accepted function of the AFW system, OPERABILITY (i.e., the intended safety function) continues to be maintained.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages AFW System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.3 REQUIREMENTS (continued)

This SR verifies that AFW can be delivered to the steam generators in the event of any accident or transient that generates an ESFAS, by demonstrating that each automatic valve in the flow path actuates to its correct position on an actual or simulated actuation (automatic pump start) signal. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.7.5.3 Note SR 3.7.5.4 This SR verifies that the AFW pumps will start in the event of any accident or transient that generates an ESFAS by demonstrating that T I

each AFW pump starts automatically on an actual or simulated actuation signal in MODES 1, 2, and 3. The motor-driven pumps must be verified to start on SI, SG water level low-low in any SG, and loss of offsite power. The turbine-driven pump must be verified to start on under-voltage on two out of three RCP buses and SG water level low-low in two SGs. The Surveillance Frequency is controlled under the Surveillance Frequency Control Programtw Notes. The first Note This SR is modified by indicates the SR may be deferred until suitable test conditions are established. This deferral is required IINSERT - BASES because there is insufficient steam pressure to perform the test.

SR 3.7.5.4 Note SR 3.7.5.5 This SR verifies that the air stored in turbine-driven AFW pump steam admission valve air accumulators is sufficient to open valves Q1 (2)N12V001A-A and Q1(2)N12V001B-B. Each steam admission valve has an air accumulator associated with it. The air accumulators provide sufficient air to ensure the operation of the steam admission valves for turbine-driven AFW pump during a loss of power or other (continued)

Farley Units 1 and 2 B 3.7.5-9 Revision luz 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT: Bases SR 3.7.5.3 Note JTTF245]

The SR is modified by a Note that states one or more AFW trains may be considered OPERABLE during alignment and operation for steam generator level control, if it is capable of being manually (i.e., remotely or locally, as appropriate) realigned to the AFW mode of operation, provided it is not otherwise inoperable. This exception allows the system to be out of its normal standby alignment and temporarily incapable of automatic initiation without declaring the train(s) inoperable. Since AFW may be used during startup, shutdown, hot standby operations, and hot shutdown operations for steam generator level control, and these manual operations are an accepted function of the AFW system, OPERABILITY (i.e., the intended safety function) continues to be maintained.

INSERT: Bases SR 3.7.5.4 Note

~245 The second Note states that one or more AFW trains may be considered OPERABLE during alignment and operation for steam generator level control, if it is capable of being manually (i.e.,

remotely or locally, as appropriate) realigned to the AFW mode of operation, provided it is not otherwise inoperable. This exception allows the system to be out of its normal standby alignment and temporarily incapable of automatic initiation without declaring the train(s) inoperable. Since AFW may be used during startup, shutdown, hot standby operations, and hot shutdown operations for steam generator level control, and these manual operations are an accepted function of the AFW system, OPERABILITY (i.e., the intended safety function) continues to be maintained.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES AC Sources -

Operating B 3.8.1 ACTIONS A.3 (continued) this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System.

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

h d -,uet,,

FiTe fo Requi, *d Actia, A.3 estb;isl i lWmi oan the m~aximum time allewed fer any eombimation of requied AC powcr sources to be inoperable d i

,,,e contguotis occurfenee of failing to meeot the LCO. if Condition A isc cnterod while, for mstence, a 9G is inepeffable and tthat DOG i* cubcoqUontlY roturnod OPERABLE, the CO mRay lr.ady have boon not mat for up to 13 days. This could lead to a total. -f 1 d-y, I-I in WWI failuro to Metthe LCO, to restore the effaite eoreuft. ;At this time, a DC could agaim becm in rable, the eircuit rcstercd O-PERABL=E, and an Odditio*l18 dy (fo Fa total of 23 days) allewed prior to comnplete rst of the LCO.. The 13 day C

'-.potien Time pr.. vid. s a limit o the me allowed a specified d...i.i. after diseevery of failure to meet the LCO. This limit is soncidoerod ro-aaconable-for situation-i whioh Cond^tien^

A and B arc

• .t...

d ooner....tly.

,^AND, connactor hotfAoona the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> an~d 13 day Cmlto io on ihat buyo, Crnpletiu,, Tii,,s apply siIImultanIeuusly, dd the iu,"r roStrietive Completion Time must be met.

As :-r

.equ

.red A,ti.n A.2, the Complctio Timc SHllOWe foran exception toJ the~ I IIJI tille zia ~"

fiji beginning~ the~ alloweid outa~ge timon "olook." This will rosult -H establiching the "time zoro" at the timc that t.

was, iftia::y iot rnet, ;uistead of at the tire.... d.to.. A I

Is-eLtereclI B._1 The Condition B Required Actions are modified by a Note that is applicable when only one of the three individual DGs is inoperable.

The note permits the use of the provisions of LCO 3.0.4c. The allowance provided by this note, to enter the MODE of applicability with a single inoperable DG, takes into account the capacity and capability of the remaining AC sources and the fact that operation is ultimately limited by the Condition B Completion Time for the inoperable DG set.

(continued)

Farley Units 1 and 2 B 3.8.1-8 Revisionp I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES AC Sources -

Operating B 3.8.1 ACTIONS (continued)

B.4 Operation may continue in Condition B for a period that should not exceed 10 days.

In Condition B, the remaining OPERABLE DG set and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. The 10 day Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period. FTSTF-439 I The..... dCornpletion Time.... RequiIed......

B4...

is lirn't on the mAximum timoe allowed for anRy combiAh2tion -of raquired A C power sources to be inoperable A,ring a-n single config, in, is

.. eu...n..

of failing to meet the I GO If COndition B3 i6,n÷tr-d w'hile, o;5 instemee, am effsite eircuit b r-prol and that pircuit ic subsequently roctored OPERABL6E, the LCO m~ay already have been nout nr u*t k up iu 72 hiuu,i.

Tisb cuuld lead to a tuotal of 13 days, suine i:tia;01faoltUv-tU iuet th~lCOt, tuloretvie thiED.

At thioUiniv, ano fit

&W

.it oauld again bee e inoprable, thoe D ret.r..d OERABE, and on addfitioa! 72 hor fr oa f 16 days) allowed prior to coim plet1 estoi stier of the LCO). The 13 day Completien Time przvides a lIm* oiI time allowle ;m a speIfIied 11*dIi/to*

afte1 Ji*lO-Vy of failure tu niii, thi LCm. This,,i,,,t ea.,idered,esonble for,ituatine* in "h"h C,,nditi... A and B arc entered oonzUrrontly. Tho "AND" etdar beween the 10 day and 13 day CompletiRn Timro, means that beth Cempletion Times apply cimultaneously, and the FAorQ

,estritie Completio;n Ti.me must be met As in RI.uir.d Action 8.2, the ComF)pletion Ti-m-e 2110 fo-r nIl eXceptioLn to t11 IInonl "iII e lUl" I

beginning thI allowed tiIme "clock." This wln ='-

nelt mt establishifg the "time er," at the time that the L-Or wa Rnial'nt mat. nta of 2t the time Conditon B woe9 enter'ed C.1 and C.2 Required Action C.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features is reduced to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is that Regulatory Guide 1.93 (Ref. 6) allows a Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for two required offsite (continued)

Farley Units 1 and 2 B 3.8.1-11 Revision=1 IF171 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages AC Sources -

Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.5 (continued)

REQUIREMENTS The design of fuel transfer systems is such that pumps operate automatically or must be started manually in order to maintain an adequate volume of fuel oil in the day tanks during or following DG testing. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.6 See SR 3.8.1.2.

SR 3.8.1.7 Transfer of the unit power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. Any change in the components being tested by this SR will require reevaluation of STI Evaluation Number 558904 in accordance with the Surveillance Frequency Control Program.

This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could T

-283 challenge continued steady state operation and, as a result, unit I

I safety systems.

\\*

-tnsert 1 -Bases3.8.1 SR 3.8.1.8 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and while maintaining a specified margin to the overspeed trip. The single load for each DG is approximately 1000 kW. This Surveillance may be accomplished by:

(continued)

Farley Units 1 and 2 B 3.8.1-20 Revision=Flrý to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert 1 - Bases 3.8.1 ITTF283I This restriction from normally performing the Surveillance in MODE 1 or 2 is further amplified to allow the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed Surveillance, a successful Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when the Surveillance is performed in MODE 1 or 2. Risk insights or deterministic methods may be used for this assessment.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages AC Sources-- Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.9 (continued)

REQUIREMENTS For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or residual heat removal (RHR) systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and ITSTF-283 temperature maintained consistent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.10

-nsert2-Bases3.8.1 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (12 seconds) from the design basis actuation signal (LOCA signal) and operates for >_ 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.10.d and SR 3.8.1.10.e ensure that permanently connected loads and emergency loads are energized from the offsite electrical power system on an ESF signal without loss of offsite power. Emergency loads are started simultaneously by logic in the load sequencers sensing the availability of offsite power.

(continued)

Farley Units 1 and 2 B 3.8.1-22 Revision=cai to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Insert 2 - Bases 3.8.1 LITSF28 This restriction from normally performing the Surveillance in MODES 1, 2, 3 or 4 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g.

post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODES 1, 2, 3 or 4. Risk insights or deterministic methods may be used for this assessment.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages AC Sources -

Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.13 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 12 seconds. The 12 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> at full load conditions prior to performance of this Surveillance is consistent with the manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.

SR 3.8.1.14 As required by Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(6),

this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and the DG can be returned to ready to load status when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs.

The DG is considered to be in ready to load status when the DG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

I This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

(continued)

Farley Units 1 and 2 B 3.8.1-25 RevisionF&P to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages AC Sources -

Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.17 (continued)

REQUIREMENTS adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations for DGs. The reason for Note 2 is that the performance of the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution TSF28 3 system, and challenge safety systems.

SR 3.8.1.18 Insert 2-Bases 3.8.1 This Surveillance demonstrates the DG capability to reject a load of 1200-2400 kW without overspeed tripping or exceeding the predetermined voltage limits. The DG load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a 1200-2400 kW load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection.

While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated. The DG output breaker(s) must remain closed such that the DG is connected to at least one ESF bus. All fuses and breakers on the energized ESF bus(es) must be verified not to trip.

This surveillance is modified by a note which states that testing of the shared Emergency Diesel Generator (EDG) set (EDG 1-2A or EDG 1C) on either unit may be used to satisfy this surveillance requirement (continued)

Farley Units 1 and 2 B 3.8.1-27 RevisionE2ýiýl P_-ý I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Distribution Systems -

Operating B 3.8.9 BASES ACTIONS A._I (continued) minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure.

The overall reliability is reduced, however, because a single failure in the remaining power distribution subsystems could result in the minimum required ESF functions not being supported. Therefore, the required AC buses, load centers, motor control centers, and distribution panels must be restored to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

Condition A worst scenario is one train without AC power (i.e., no offsite power to the train and the associated DG inoperable). In this Condition, the unit is more vulnerable to a complete loss of AC power.

It is, therefore, imperative that the unit operator's attention be focused on minimizing the potential for loss of power to the remaining train by stabilizing the unit, and on restoring power to the affected train. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> time limit before requiring a unit shutdown in this Condition is acceptable because of:

a. The potential for decreased safety if the unit operator's attention is diverted from the evaluations and actions necessary to restore power to the affected train, to the actions associated with taking the unit to shutdown within this time limit; and

b. The potential for an event in conjunction with a single failure of a redundant component in the train with AC power.

MIT Tie secon i, Cmpletitn Time f, r R, ui.ed Action A. 1 aetbahiheis a

.lLogl Hati th mai~i*S num.tim allowed fu. any eauinat,,ion, of require dcitrrbU.i.e subsytosms toe CinOpfablce during any cinglo eeontigereu ccu I rrenc Of fa2i1inAg to moot8_ thQe L-C -. If ConAdition-A

• s a ntere d w -h ilis L

OTPERABLE, 1:1~ LOCe mayd alieady have beem met met fer up to-iLCO, to restm1 the AC distribution syte At thi ti..., a DC circuit eO.ld again be..rm. ;maperable, ai.d AC du1,uuut,, feuoed OPERABLE. This cou-ld contnu-e indefinitely.

The Complti, n Ti*m alo*ws felan exeipto' n to the no*rmal "time zcro "

fr~r ham.,u lnnn +hm nlnudmAr ni ito ga tima "AntpL- " Thic wuill ract ~it in (continued)

Farley Units I and 2 B 3.8.9-4 Revision V]

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Distribution Systems -

Operating B 3.8.9 BASES ACTIONS A.1 (continued)

[Ts' establishing tho "tirn zoro" at the time the LCOQ was initially not mct, i nstead of the t"me Codotg A was e "tefed.

The 16 hc*u. Cmpl-ti"n Time 49 am, seeptable limitatien em this petential te fail t3 meet the B._1 With one or more AC vital buses inoperable, and a loss of safety function has not yet occurred, the remaining OPERABLE AC vital buses are capable of supporting the minimum safety functions necessary to shut down the unit and maintain it in the safe shutdown condition. Overall reliability is reduced, however, since an additional single failure could result in the minimum required ESF functions not being supported. Therefore, the required AC vital bus must be restored to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> by powering the bus from the associated inverter via inverted DC or Class 1 E constant voltage transformer.

Condition B represents one or more AC vital buses without power; potentially both the DC source and the associated AC source are nonfunctioning. In this situation, the unit is significantly more vulnerable to a complete loss of all noninterruptible power. It is, therefore, imperative that the operator's attention focus on stabilizing the unit, minimizing the potential for loss of power to the remaining vital buses and restoring power to the affected vital bus.

This 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> limit is more conservative than Completion Times allowed for the vast majority of components that are without adequate vital AC power. Taking exception to LCO 3.0.2 for components without adequate vital AC power, that would have the Required Action Completion Times shorter than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> if declared inoperable, is acceptable because of:

a. The potential for decreased safety by requiring a change in unit conditions (i.e., requiring a shutdown) and not allowing stable operations to continue; (continued)

Farley Units 1 and 2 B 3.8.9-5 Revisionf&_ý to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES Distribution Systems -

Operating B 3.8.9 ACTIONS B.1 (continued)

b. The potential for decreased safety by requiring entry into numerous Applicable Conditions and Required Actions for components without adequate vital AC power and not providing sufficient time for the operators to perform the necessary evaluations and actions for restoring power to the affected train; and

c. The potential for an event in conjunction with a single failure of a redundant component.

The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> Completion Time takes into account the importance to safety of restoring the AC vital bus to OPERABLE status, the redundant capability afforded by the other OPERABLE vital buses, and the low probability of a DBA occurring during this period.

I7 Tit: scui,,d Cu,,,;pletion Tim*;e for Requied Act;on 0. 1 establishes a lknit on thce -ximum time allowed f. r an7 mb..atiom of require_

d distribution sbsystCrns~ to be imapervable duim amy sirile earitigueu3 oo~eetrome of failing to mooet the LCO. if Conditien B io entcrcd whioc,,

for omstamee, arn AC bus is ineperablc and subsequently rotuno

.PERABLE, t!

Lte

, my a'.

yady have beett mot n efi ut*,

8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. This eoud Iead tU a total of 16 h*our, siroc initial failure af the LCO), to festcro the vital bus distribuJtion system. At this time, an AG train osuld again beeeme inopefrable, and vital bus distfibution rotrord OPERABlE. Th GA o ld nt..u 'ndA--

it fhis eovto Time* azllows fo, ar exception to tlie nonna i 4 le zeii v rr be*i*j-,

ni-,e allCowe,.tagje tome ",l-v k., This will resu it L establishing the "timo zero" at the timec the LCO was initially not met,

• instoad of the time Condition 13 war, cntercd. Tho 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> Completoen Tim1 e is am seeeptable limitatoen on this potontial to fail to-mest the CA1 With Auxiliary Building DC bus(es) in one train inoperable, the remaining Auxiliary Building DC electrical power distribution subsystems are capable of supporting the minimum safety functions (continued)

Farley Units 1 and 2 B 3.8.9-6 Revisionr=IV I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages BASES Distribution Systems -Operating B 3.8.9 ACTIONS C..

(continued)

T9he see U onpetion Time fo, Required Acti,, G..

establishes a limit m

,,the

,,,,,um

,re aowed fe. any.

.mbination of ro..irod d-istri-bu-tion subsystamrs to be inoperable during any single contiguous oAuPcnoez Af failing to mct the LCO. If A

enditien C is entered while fer instenee, an AC bus is inepemble and subsequently rcturnzmed OPERABL6E, the LCO may alrcady have been net met for up to 0 how,.Tin; cold lead lo a tetal ef 10 houfs, sinee initial feolurz cf the LCO, to Fcctoro the PIG dictributonA system. At this time, an AC train could again beceme imapefeble, and 9G diStribution rz~tOFc This eompet;on Time alkews for am exeeptien to the norfmal "timeizero" foi beg11r.,g the allew~ed autage time "laek~.ll This will resuti establishim the "tirme rere" at the time the LCOe was initially net met,

'm~tead of the tifne CGndifien C was enterzd. The 16 hour1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> Gompletion I Imeils an accp*c ble lIItationI ui IlIsi I*jotenial to fai*to, I1 eet thc D.1 and D.2 If the inoperable distribution subsystem(s) addressed by Conditions A, B, or C cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

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

E. 1 With one SWIS DC electrical power distribution subsystem inoperable, the Service Water System train supported by the affected SWIS DC electrical power distribution subsystem must be declared inoperable.

The capability of the affected SWIS DC electrical power distribution subsystem to fully support the associated train of Service Water is not assured. Therefore, consistent with the definition of OPERABILITY, the associated train of Service Water must be declared inoperable immediately, thereby limiting operation in this condition to the Completion Time associated with the affected Service Water System train.

(continued)

Farley Units 1 and 2 B 3.8.9-8 RevisionW7 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Boron Concentration B 3.9.1 BASES LCO (continued) boron concentration limit specified in the COLR ensures that a core keff of _< 0.95 is maintained during fuel handling operations. Violation of the LCO could lead to an inadvertent criticality during MODE 6.

APPLICABILITY This LCO is applicable in MODE 6 to ensure that the fuel in the reactor vessel will remain subcritical. The required boron concentration ensures a keff < 0.95. In other MODES, the LCOs for Rod Group Alignment Limits, Shutdown Bank Insertion Limits, Control Bank Insertion Limits, and SHUTDOWN MARGIN ensure that an adequate amount of negative reactivity is available to shut down the 'TSTF-272' reactor and maintain it subcritical.

I2 I

ACTIONS The Applicability is modified by a Note. The Note states that the limits on boron concentration are only applicable to the refueling canal and the refueling cavity when those volumes are connected to the Reactor Coolant System. When the refueling canal and the refueling cavity are isolated from the RCS, no potential path for boron dilution exists.

A.1 and A.2 Continuation of CORE ALTERATIONS or positive reactivity additions (including actions to reduce boron concentration) is contingent upon maintaining the unit in compliance with the LCO. If the boron concentration of any coolant volume in the filled portions of the RCS, the refueling canal, or the refueling cavity that has direct access to the core is less than its limit, all operations involving CORE ALTERATIONS or positive reactivity additions must be suspended immediately.

Suspension of CORE ALTERATIONS and positive reactivity additions shall not preclude moving a component to a safe position or normal cooling of the coolant volume for the purpose of maintaining system temperature.

A.3 In addition to immediately suspending CORE ALTERATIONS or positive reactivity additions, boration to restore the concentration must be initiated immediately.

In determining the required combination of boration flow rate and concentration, no unique Design Basis Event must be satisfied. The only requirement is to restore the boron concentration to its required value as soon as possible. In order to raise the boron concentration as soon as possible, the operator should begin boration with the best source available for unit conditions.

Once actions have been initiated, they must be continued until the boron concentration is restored. The restoration time depends on the amount of boron that must be injected to reach the required concentration.

Farley Units 1 and 2 B 3.9.1-3 Revision 17':-'

lu-I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Boron Concentration 83.9.1 BASES land connected portions ofI SURVEILLANCE REQUIREMENTS SR 3.9.1.1 This SR ensures ths, tthe coolant boron concentration in the filled portions of the RCS, 'the refueling canal~nd the refueling cavity at have direct access to the core is within the COLR limits. The boron concentration of the coolant in each,volume that has direct access to the core is determined periodically chemical analysis The Surveillance Frequency is controlld under the rveillance I

Frequency Control Program.

Irequired I ITS'TF-27 REFERENCES

1. 10 CFR 50, Appendix A, GDC 26.

2. FSAR, Chapter 15.2.4.

Prior to re-connecting portions of the refueling canal or the refueling cavity to the RCS, this SR must be met per SR 3.0.4. If any dilution has occurred while the cavity or canal were disconnected from the RCS, this SR ensures the correct boron concentration prior to communication with the RCS.

Farley Units 1 and 2 B 3.9.1-4 RevisionI571 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Containment Penetrations B 3.9.3 BASES LCO (continued) are terminated, such that radiological doses are within the acceptance limit.

The equipment hatch and personnel air locks are considered isolable I

when the following criteria are satisfied:

1.

the necessary equipment required to close the hatch and personnel air locks is available,

2.

at least 23 feet of water is maintained over the top of the reactor vessel flange in accordance with Specification 3.9.6,

3.

a designated trained closure crew is available.

I The equipment hatch and personnel air locks door openings must be capable of being cleared of any obstruction so that closure can be achieved as soon as possible.

The containment personnel air lock and emergency personnel air lock doors may be open during movement of irradiated fuel in the containment and during CORE ALTERATIONS provided that one door in each air lock is capable of being closed in the event of a fuel handling accident. Should a fuel handling accident occur inside containment, one door in each personnel air lock will be closed following an evacuation of containment.

The closure of the equipment hatch and the personnel air locks will INSERT - Bases LCO 3.9.3 completed promptly following a fuel handling accident within Note N

containment.

be ITSTF-312I APPLICABILITY The containment penetration requirements are applicable during CORE ALTERATIONS or movement of irradiated fuel assemblies within containment because this is when there is a potential for a fuel handling accident. In MODES 1, 2, 3, and 4, containment penetration requirements are addressed by LCO 3.6.1. In MODES 5 and 6, when CORE ALTERATIONS or movement of irradiated fuel assemblies within containment are not being conducted, the potential for a fuel handling accident does not exist. Therefore, under these conditions no requirements are placed on containment penetration status.

Farley Units 1 and 2 B 3.9.3-4 RevisionE_ý"

1ýý I to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages INSERT - Bases LCO 3.9.3 Note ITTF312I The LCO is modified by a Note allowing penetration flow paths with direct access from the containment atmosphere to the outside atmosphere to be unisolated under administrative controls. Administrative controls ensure that 1) appropriate personnel are aware of the open status of the penetration flow path during CORE ALTERATIONS or movement of irradiated fuel assemblies within containment, and 2) specified individuals are designated and readily available to isolate the flow path in the event of a fuel handling accident.

to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages Containment Penetrations B 3.9.3 BASES SURVEILLANCE REQUIREMENTS SR 3.9.3.2 (continued) isolation time of each valve is in accordance with the Inservice Testing Program requirements. These Surveillances performed during MODE 6 will ensure that the valves are capable of closing after a postulated fuel handling accident to limit a release of fission product I radioactivity from the containment.

TSTF-284I The SR is modified by a Note stating that this Surveillance is not required to be met for valves in isolated penetrations. The LCO provides the option to close penetrations in lieu of requiring automatic actuation capability.

I SR 3.9.3.3 The equipment hatch is provided with a set of hardware, tools, and equipment for moving the hatch from its storage location and installing it in the opening. The required set of hardware, tools, and equipment shall be inspected to ensure that they can perform the required functions.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note which only requires that the surveillance be met for an open equipment hatch. If the equipment hatch is installed in its opening, the availability of the means to install the hatch is not required.

REFERENCES

1. GPU Nuclear Safety Evaluation SE-0002000-001, Rev. 0, May 20, 1988.

2. FSAR, Section 15.4.5.

3. NUREG-0800, Section 15.7.4, Rev. 1, July 1981.

4. Regulatory Guide 1.195, "Methods and Assumptions for Evaluating Radiological Consequences of Design Basis Accidents at Light-Water Nuclear Power Reactors," May 2003.

Farley Units 1 and 2 B 3.9.3-6 Revisionriz 1 to NL-14-1385 Example Marked-Up Technical Specifications Bases Pages RHR and Coolant Circulation -

Low Water Level B 3.9.5 BASES LCO (continued)

An OPERABLE RHR loop consists of an RHR pump, a heat exchanger, valves, piping, instruments and controls to ensure an OPERABLE flow path and to determine the low end temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS culu d Itwo Notes. The first Note I The LCO requirements are modified byaJrNote-wh"hProvides an exception to the requirements for one RHR loop to be OPERABLE and one RHR loop to be in operation. This exception is necessary to JTSTF-34 ensure the RHR System may be realigned as necessary for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to perform the required surveillance testing necessary to verify the RHR System performance in the ECCS injection mode of operation.

A APPLICABILITY wo RHR loops are required to be OPERABLE, and one RHR loop ust be in operation in MODE 6, with the water level < 23 ft above the

op of the reactor vessel flange, to provide decay heat removal.

Requirements for the RHR System in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS), and Section 3.5, Emergency Core Cooling Systems (ECCS). RHR loop requirements in MODE 6 with the water level >_ 23 ft are located in LCO 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level."

ACTIONS The second Note permits the RHR pumps to be de-energized for </= 15 minutes when switching from one train to another. The circumstances for stopping both RHR pumps are to be limited to situations when the outage time is short (and the core outlet temperature is limited to > 10 degrees F below saturation temperature). The Note prohibits boron dilution or draining operations when RHR forced flow is stopped.

A.1 and A.2 If less than the required number of RHR loops are OPERABLE, action shall be immediately initiated and continued until the RHR loop is restored to OPERABLE status and to operation or until > 23 ft of water level is established above the reactor vessel flange. When the water level is > 23 ft above the reactor vessel flange, the Applicability changes to that of LCO 3.9.4, and only one RHR loop is required to be OPERABLE and in operation. An immediate Completion Time is necessary for an operator to initiate corrective actions.

B._1 If no RHR loop is in operation, there will be no forced circulation to provide mixing to establish uniform boron concentrations. Reduced boron concentrations can occur by the addition of water with a lower boron concentration than the required boron concentration specified in the COLR. Therefore, actions that could result in the addition of water to the RCS with a boron concentration less than the required boron concentration specified in the COLR must be suspended immediately.

(continued)

Farley Units 1 and 2 B 3.9.5-2 Revision=[p-- I

Joseph M. Farley Nuclear Plant - Units 1 and 2 Request for Technical Specification Amendment Adoption of Previously NRC-Approved Generic Technical Specification Changes and Other Changes Clean-Typed Technical Specifications Pages to NL-14-1385 Clean-Typed Technical Specifications Pages 1.1 Definitions Definitions 1.1 PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR)

QUADRANT POWER TILT RATIO (QPTR)

RATED THERMAL POWER (RTP)

REACTOR TRIP SYSTEM (RTS) RESPONSE TIME SHUTDOWN MARGIN (SDM)

The PTLR is the unit specific document that provides the reactor vessel pressure and temperature limits, including heatup and cooldown rates and the Low Temperature Overpressure Protection System applicability temperature, for the current reactor vessel fluence period. These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 5.6.6.

QPTR shall be the ratio of the maximum upper excore detector calibrated output to the average of the upper excore detector calibrated outputs, or the ratio of the maximum lower excore detector calibrated output to the average of the lower excore detector calibrated outputs, whichever is greater.

RTP shall be a total reactor core heat transfer.rate to the reactor coolant of 2775 MWt.

The RTS RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its RTS trip setpoint at the channel sensor until loss of stationary gripper coil voltage. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and the methodology for verification have been previously reviewed and approved by the NRC.

SDM shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming:

a.

All rod cluster control assemblies (RCCAs) are fully inserted except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn.

However, with all RCCAs verified fully inserted by two independent means, it is not necessary to account for a stuck RCCA in the SDM calculation. With any RCCA not capable of being fully inserted, the reactivity worth of the RCCA must be accounted for in the determination of SDM; and (continued)

Farley Units 1 and 2 1.1-5 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Completion Times 1.3 1.3 Completion Times DESCRIPTION (continued) limits, the Completion Time(s) may be extended. To apply this Completion Time extension, two criteria must first be met. The subsequent inoperability:

a.

Must exist concurrent with the first inoperability; and

b.

Must remain inoperable or not within limits after the first inoperability is resolved.

The total Completion Time allowed for completing a Required Action to address the subsequent inoperability shall be limited to the more restrictive of either:

a.

The stated Completion Time, as measured from the initial entry into the Condition, plus an additional 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />; or

b.

The stated Completion Time as measured from discovery of the subsequent inoperability.

The above Completion Time extensions do not apply to those Specifications that have exceptions that allow completely separate re-entry into the Condition (for each train, subsystem, component, or variable expressed in the Condition) and separate tracking of Completion Times based on this re-entry. These exceptions are stated in individual Specifications.

The above Completion Time extension does not apply to a Completion Time with a modified "time zero." This modified "time zero" may be expressed as a repetitive time (i.e., "once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />," where the Completion Time is referenced from a previous completion of the Required Action versus the time of Condition entry) or as a time modified by the phrase "from discovery..."

Farley Units 1 and 2 1.3-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Completion Times 1.3 1.3 Completion Times EXAMPLES (continued)

EXAMPLE 1.3-3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One A.1 Restore 7 days Function X Function X train train to OPERABLE inoperable, status.

B.

One B.1 Restore 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Function Y Function Y train train to OPERABLE inoperable, status.

C. One C.1 Restore 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Function X Function X train train to OPERABLE inoperable, status.

AND OR One C.2 Restore 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Function Y Function Y train train to OPERABLE inoperable, status.

(continued)

Farley Units 1 and 2 1.3-6 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages 1.3 Completion Times Completion Times 1.3 EXAMPLES EXAMPLE 1.3-3 (continued)

When one Function X train and one Function Y train are inoperable, Condition A and Condition B are concurrently applicable. The Completion Times for Condition A and Condition B are tracked separately for each train starting from the time each train was declared inoperable and the Condition was entered. A separate Completion Time is established for Condition C and tracked from the time the second train was declared inoperable (i.e., the time the situation described in Condition C was discovered).

If Required Action C.2 is completed within the specified Completion Time, Conditions B and C are exited. If the Completion Time for Required Action A.1 has not expired, operation may continue in accordance with Condition A. The remaining Completion Time in Condition A is measured from the time the affected train was declared inoperable (i.e., initial entry into Condition A).

It is possible to alternate between Conditions A, B, and C in such a manner that operation could continue indefinitely without ever restoring systems to meet the LCO. However, doing so would be inconsistent with the basis of the Completion Times. Therefore, there shall be administrative controls to limit the maximum time allowed for any combination of Conditions that result in a single contiguous occurrence of failing to meet the LCO. These administrative controls shall ensure that the Completion Times for those Conditions are not inappropriately extended.

(continued)

Farley Units 1 and 2 1.3-7 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Frequency 1.4 1.0 USE AND APPLICATION 1.4 Frequency PURPOSE The purpose of this section is to define the proper use and application of Frequency requirements.

DESCRIPTION Each Surveillance Requirement (SR) has a specified Frequency in which the Surveillance must be met in order to meet the associated LCO. An understanding of the correct application of the specified Frequency is necessary for compliance with the SR.

The "specified Frequency" is referred to throughout this section and each of the Specifications of Section 3.0, Surveillance Requirement (SR)

Applicability. The "specified Frequency" consists of the requirements of the Frequency column of each SR as well as certain Notes in the Surveillance column that modify performance requirements.

Sometimes special situations dictate when the requirements of a Surveillance are to be met. They are "otherwise stated" conditions allowed by SR 3.0.1. They may be stated as clarifying Notes in the Surveillance, as part of the Surveillance, or both.

Situations where a Surveillance could be required (i.e., its Frequency could expire), but where it is not possible or not desired that it be performed until sometime after the associated LCO is within its Applicability, represent potential SR 3.0.4 conflicts. To avoid these conflicts, the SR (i.e., the Surveillance or the Frequency) is stated such that it is only "required" when it can be and should be performed. With an SR satisfied, SR 3.0.4 imposes no restriction.

The use of "met" or "performed" in these instances conveys specific meanings. A Surveillance is "met" only when the acceptance criteria are satisfied. Known failure of the requirements of a Surveillance, even without a Surveillance specifically being "performed," constitutes a Surveillance not "met." "Performance" refers only to the requirement to specifically determine the ability to meet the acceptance criteria. Some Surveillances contain notes that modify the Frequency of performance or the conditions during which the acceptance criteria must be satisfied. For these Surveillances, the MODE-entry restrictions of SR 3.0.4 may not apply. Such a Surveillance is not required to be performed prior to entering a MODE or other specified condition in the Applicability of the associated LCO if any of the following three conditions are satisfied:

(continued)

Farley Units 1 and 2 1.4-1 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Frequency 1.4 1.4 Frequency DESCRIPTION (continued)

a.

The Surveillance is not required to be met in the MODE or other specified condition to be entered; or

b.

The Surveillance is required to be met in the MODE or other specified condition to be entered, but has been performed within the specified Frequency (i.e., it is current) and is known not to be failed; or

c.

The Surveillance is required to be met, but not performed, in the MODE or other specified condition to be entered, and is known not to be failed.

Examples 1.4-3, 1.4-4, 1.4-5, and 1.4-6 discuss these special situations.

EXAMPLES The following examples illustrate the various ways that Frequencies are specified. In these examples, the Applicability of the LCO (LCO not shown) is MODES 1, 2, and 3.

EXAMPLE 1.4-1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Perform CHANNEL CHECK.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Example 1.4-1 contains the type of SR most often encountered in the Technical Specifications (TS). The Frequency specifies an interval (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) during which the associated Surveillance must be performed at least one time. Performance of the Surveillance initiates the subsequent interval. Although the Frequency is stated as 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, an extension of the time interval to 1.25 times the stated Frequency is allowed by SR 3.0.2 for operational flexibility. The measurement of this interval continues at all times, even when the SR is not required to be met per SR 3.0.1 (such as when the equipment is inoperable, a variable is outside specified limits, or the unit is outside the Applicability of the LCO). If the interval specified by SR 3.0.2 is exceeded while the unit is in a MODE or other specified condition in the Applicability of the LCO, and the performance of the Surveillance is not otherwise modified (refer to Example 1.4-3), then SR 3.0.3 becomes applicable.

(continued)

Farley Units 1 and 2 1.4-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Frequency 1.4 1.4 Frequency EXAMPLES EXAMPLE 1.4-1 (continued)

If the interval as specified by SR 3.0.2 is exceeded while the unit is not in a MODE or other specified condition in the Applicability of the LCO for which performance of the SR is required, then SR 3.0.4 becomes applicable. The Surveillance must be performed within the Frequency requirements of SR 3.0.2, as modified by SR 3.0.3, prior to entry into the MODE or other specified condition or the LCO is considered not met (in accordance with SR 3.0.1) and LCO 3.0.4 becomes applicable.

EXAMPLE 1.4-2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY Verify flow is within limits.

Once within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after

Ž 25% RTP AND 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter Example 1.4-2 has two Frequencies. The first is a one time performance Frequency, and the second is of the type shown in Example 1.4-1. The logical connector "AND" indicates that both Frequency requirements must be met. Each time reactor power is increased from a power level

< 25% RTP to > 25% RTP, the Surveillance must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

The use of "once" indicates a single performance will satisfy the specified Frequency (assuming no other Frequencies are connected by "AND").

This type of Frequency does not qualify for the 25% extension allowed by SR 3.0.2. "Thereafter" indicates future performances must be established per SR 3.0.2, but only after a specified condition is first met (i.e., the "once" performance in this example). If reactor power decreases to

< 25% RTP, the measurement of both intervals stops. New intervals start upon reactor power reaching 25% RTP.

(continued)

Farley Units 1 and 2 1.4-3 Amendment No.

Amendment No.

(Unit 1) I (Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Frequency 1.4 1.4 Frequency EXAMPLES (continued)

EXAMPLE 1.4-3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY NOTE --------------

Not required to be performed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after

_> 25% RTP.

Perform channel adjustment.

7 days The interval continues, whether or not the unit operation is < 25% RTP between performances.

As the Note modifies the required performance of the Surveillance, it is construed to be part of the "specified Frequency." Should the 7 day interval be exceeded while operation is < 25% RTP, this Note allows 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after power reaches > 25% RTP to perform the Surveillance.

The Surveillance is still considered to be performed within the "specified Frequency." Therefore, if the Surveillance were not performed within the 7 day (plus the extension allowed by SR 3.0.2) interval, but operation was

< 25% RTP, it would not constitute a failure of the SR or failure to meet the LCO. Also, no violation of SR 3.0.4 occurs when changing MODES, even with the 7 day Frequency not met, provided operation does not exceed 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> with power _> 25% RTP.

Once the unit reaches 25% RTP, 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> would be allowed for completing the Surveillance. If the Surveillance were not performed within this 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> interval, there would then be a failure to perform a Surveillance within the specified Frequency, and the provisions of SR 3.0.3 would apply.

(continued)

Farley Units 1 and 2 1.4-4 Amendment No. 170 (Unit 1)

Amendment No. 163 (Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages 1.4 Frequency Frequency 1.4 EXAMPLES (continued)

EXAMPLE 1.4-4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY NOTE --------------

Only required to be met in MODE 1.

Verify leakage rates are within limits.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Example 1.4-4 specifies that the requirements of this Surveillance do not have to be met until the unit is in MODE 1. The interval measurement for the Frequency of this Surveillance continues at all times, as described in Example 1.4-1. However, the Note constitutes an "otherwise stated" exception to the Applicability of this Surveillance. Therefore, if the Surveillance were not performed within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> interval (plus the extension allowed by SR 3.0.2), but the unit was not in MODE 1, there would be no failure of the SR nor failure to meet the LCO. Therefore, no violation of SR 3.0.4 occurs when changing MODES, even with the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency exceeded, provided the MODE change was not made into MODE 1. Prior to entering MODE 1 (assuming again that the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency were not met), SR 3.0.4 would require satisfying the SR.

EXAMPLE 1.4-5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY NOTE --------------

Only required to be performed in MODE 1.

Perform complete cycle of the valve.

7 days (continued)

Farley Units 1 and 2 1.4-5 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages 1.4 Frequency Frequency 1.4 EXAMPLES EXAMPLE 1.4-5 (continued)

The interval continues, whether or not the unit operation is in MODE 1, 2, or 3 (the assumed Applicability of the associated LCO) between performances.

As the Note modifies the required performance of the Surveillance, the Note is construed to be part of the "specified Frequency." Should the 7 day interval be exceeded while operation is not in MODE 1, this Note allows entry into and operation in MODES 2 and 3 to perform the Surveillance. The Surveillance is still considered to be performed within the "specified Frequency" is completed prior to entering MODE 1.

Therefore, if the Surveillance were not performed within the 7 day (plus the extension allowed by SR 3.0.2) interval, but operation was not in MODE 1, it would not constitute a failure of the SR or failure to meet the LCO. Also, no violation of SR 3.0.4 occurs when changing MODES, even with the 7 day Frequency not met, provided operation does not result in entry into MODE 1.

Once the unit reaches MODE 1, the requirement for the Surveillance to be performed within its specified Frequency applies and would require that the Surveillance had been performed. If the Surveillance were not performed prior to entering MODE 1, there would then be a failure to perform a Surveillance within the specified Frequency, and the provisions of SR 3.0.3 would apply.

EXAMPLE 1.4-6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY

-NOTE Not required to be met in MODE 3.

Verify parameter is within limits 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (continued)

Farley Units 1 and 2 1.4-6 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages 1.4 Frequency Frequency 1.4 EXAMPLES EXAMPLE 1.4-6 (continued)

Example 1.4-6 specifies that the requirements of this Surveillance do not have to be met while the unit is in MODE 3 (the assumed Applicability of the associated LCO is MODES 1, 2, and 3). The interval measurement for the Frequency of this Surveillance continues at all times. As described in Example 1.4-1, however, the Note constitutes an "otherwise stated" exception to the applicability of this Surveillance. Therefore, if the Surveillance were not performed within the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> interval (plus the extension allowed by SR 3.0.2), and the unit was in MODE 3, there would be no failure of the SR nor failure to meet the LCO. Therefore, no violation of SR 3.0.4 occurs when changing MODES to enter MODE 3, even with the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency exceeded, provided the MODE change does not result in entry into MODE 2. Prior to entering MODE 2 (assuming again that the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency were not met), SR 3.0.4 would require satisfying the SR.

Farley Units 1 and 2 1.4-7 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Rod Group Alignment Limits 3.1.4 ACTIONS CONDITION R

REQUIRED ACTION COMPLETION TIME B.

(continued)

B.2.1.2 Initiate boration to restore SDM to within limit.

AND B.2.2 Reduce THERMAL POWER to *75% RTP.

AND B.2.3 Verify SDM to be within the limits provided in the COLR.

AND B.2.4 Perform SR 3.2.1.1 and SR 3.2.1.2.

AND B.2.5 Perform SR 3.2.2.1.

AND B.2.6 Re-evaluate safety analyses and confirm results remain valid for duration of operation under these conditions.

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 2 hours Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 72 hours 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> 5 days C.

Required Action and C.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition B not met.

Farley Units 1 and 2 3.1.4-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages PHYSICS TESTS Exceptions-MODE 2 3.1.8 3.1 REACTIVITY CONTROL SYSTEMS 3.1.8 PHYSICS TESTS Exceptions-MODE 2 LCO 3.1.8 During the performance of PHYSICS TESTS, the requirements of LCO 3.1.3, "Moderator Temperature Coefficient (MTC)";

LCO 3.1.4, "Rod Group Alignment Limits";

LCO 3.1.5, "Shutdown Bank Insertion Limits";

LCO 3.1.6, "Control Bank Insertion Limits"; and LCO 3.4.2, "RCS Minimum Temperature for Criticality" may be suspended and the number of required channels for LCO 3.3.1, "RTS Instrumentation," Functions 2, 3, and 17.e, may be reduced to 3, provided:

a.

THERMAL POWER is < 5% RTP;

b.

SDM is within the limits provided in the COLR; and

c.

RCS lowest loop average temperature is a 531'F.

APPLICABILITY:

MODE 2 during PHYSICS TESTS.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

SDM not within limit.

A.1 Initiate boration to Immediately restore SDM to within limit.

AND A.2 Suspend PHYSICS 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> TESTS exceptions.

B.

THERMAL POWER not B. 1 Open reactor trip Immediately within limit, breakers.

Farley Units 1 and 2 3.1.8-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages 3.2 POWER DISTRIBUTION LIMITS 3.2.4 QUADRANT POWER TILT RATIO (QPTR)

QPTR 3.2.4 LCO 3.2.4 The QPTR shall be < 1.02.

APPLICABILITY:

MODE 1 with THERMAL POWER Ž 50% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

QPTR not within limit.

A.1 Limit THERMAL 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after each POWER to _>

3% below QPTR determination RTP for each 1% of QPTR > 1.00.

AND A.2 Determine QPTR.

Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> AND A.3 Perform SR 3.2.1.1, SR 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after 3.2.1.2, and SR 3.2.2.1.

achieving equilibrium conditions with THERMAL POWER limited by Required Action A. 1 AND Once per 7 days thereafter AND (continued)

Farley Units 1 and 2 3.2.4-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages QPTR 3.2.4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.6 -

---

NOTE------

Perform Required Action A.6 only after Required Action A.5 is completed.

Perform SR 3.2.1.1, SR 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after 3.2.1.2, and SR 3.2.2.1.

achieving equilibrium conditions at RTP OR Within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> after increasing THERMAL POWER above the limit of Required Action A. 1 B.

Required Action and B.1 Reduce THERMAL 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> associated Completion POWER to < 50% RTP.

Time not met.

Farley Units 1 and 2 3.2.4-3 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RTS Instrumentation 3.3.1 SURVEILLANCE REQUIREMENTS NOTE-Refer to Table 3.3.1-1 to determine which SRs apply for each RTS Function.

SURVEILLANCE FREQUENCY SR 3.3.1.1

---

NOTE Not required to be performed for source range instrumentation until 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> after THERMAL POWER is < P-6.

Perform CHANNEL CHECK.

In accordance with the Surveillance Frequency Control Program SR 3.3.1.2

---

NOTE Not required to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER is >_ 15% RTP.

Compare results of calorimetric heat balance In accordance with calculation to power range channel output. Adjust the Surveillance power range channel output if calorimetric heat Frequency Control balance calculation results exceed power range Program channel output by more than +2%.

SR 3.3.1.3

---

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

1.

Not required to be performed until 7 days after THERMAL POWER is _> 50% RTP.

2.

Performance of SR 3.3.1.9 satisfies this SR.

Compare results of the incore detector In accordance with measurements to Nuclear Instrumentation System the Surveillance (NIS) AFD. Adjust NIS channel if difference is Frequency Control

>! 3%.

Program Farley Units 1 and 2 3.3.1-9 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Table 3.3.1-1 (page 1 of 8)

Reactor Trip System Instrumentation RTS Instrumentation 3.3.1 APPLICABLE MODES OR NOMINAL OTHER TRIP SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE SETPOINT FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE Manual Reactor 1,2 2

B SR 3.3.1.12 NA NA Trip 3 (a), 4 (a), 5 (a) 2 C

SR 3.3.1.12 NA NA

2.

Power Range Neutron Flux

a.

High 1,2 4

D SR 3.3.1.1

< 109.4% RTP 109%

SR 3.3.1.2 RTP SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.14

b.

Low 1(b), 2 4

E SR 3.3.1.1

• 25.4% RTP 25% RTP SR 3.3.1.8 SR 3.3.1.10 SR 3.3.1.14

3.

Power Range 1,2 4

D SR 3.3.1.7

• 5.4% RTP 5% RTP Neutron Flux High SR 3.3.1.10 with time with time Positive Rate SR 3.3.1.14 constant constant

> 2 sec

? 2 sec

4.

Intermediate 1(b), 2 (c) 2 F,G SR 3.3.1.1 5 40% RTP 35% RTP Range Neutron SR 3.3.1.8 Flux SR 3.3.1.10 2(d) 2 H

SR 3.3.1.1

<40% RTP 35% RTP SR 3.3.1.8 SR 3.3.1.10 (a)

(b)

(c)

(d)

With Reactor Trip Breakers (RTBs) closed and Rod Control System capable of rod withdrawal.

Below the P-10 (Power Range Neutron Flux) interlocks.

Above the P-6 (Intermediate Range Neutron Flux) interlocks.

Below the P-6 (Intermediate Range Neutron Flux) interlocks.

Farley Units 1 and 2 3.3.1-14 Amendment No. 189 (Unit 1)

Amendment No. 184 (Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 2 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT Source Range 2(d) 2 I,J SR 3.3.1.1

• 1.3 E5 cps 1.0 E5 cps Neutron Flux SR 3.3.1.8 SR 3.3.1.10 3(a) 4 (a), 5(a) 2 J,K SR 3.3.1.1

<1.3 E5 cps 1.0 E5 cps SR 3.3.1.7 SR 3.3.1.10 3 (e), 4 (e),5(e) 1 L

SR 3.3.1.1 N/A N/A SR 3.3.1.10

6.

Overtemperature 1,2 3

E SR 3.3.1.1 Refer to Refer to AT SR 3.3.1.3 Note 1 (Page Note 1 (Page SR 3.3.1.7 3.3.1-20) 3.3.1-20)

SR 3.3.1.9 SR 3.3.1.10 SR 3.3.1.14

7.

Overpower AT 1,2 3

E SR 3.3.1.1 Refer to Refer to SR 3.3.1.7 Note 2 (Page Note 2 (Page SR 3.3.1.10 3.3.1-21) 3.3.1-21)

SR 3.3.1.14 (a)

(d)

(e)

With RTBs closed and Rod Control System capable of rod withdrawal.

Below the P-6 (Intermediate Range Neutron Flux) interlocks.

With the RTBs open. In this condition, source range Function does not provide reactor trip but does provide indication.

Farley Units 1 and 2 3.3.1-15 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 3 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

8.

Pressurizer Pressure

a.

Low 1 )

3 M

SR 3.3.1.1

_1862 psig 1865 psig SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.14

b.

High 1,2 3

E SR 3.3.1.1 5 2388 psig 2385 psig SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.14

9.

Pressurizer Water 1 ()

3 M

SR 3.3.1.1

_92.4%

92%

Level -

High SR 3.3.1.7 SR 3.3.1.10

10.

Reactor Coolant 1()

3 per loop M

SR 3.3.1.1

Ž 89.7%

90%

Flow-Low SR 3.3.1.7 SR 3.3.1.10 SR 3.3.1.14 (0)

Above the P-7 (Low Power Reactor Trips Block) interlock.

Farley Units 1 and 2 3.3.1-16 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 4 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

11.

Not used l(f)

12.

Undervoltage 3

M SR 3.3.1.6

>_ 2640 V 2680 V RCPs SR 3.3.1.10 i(f)

13.

Underfrequency 3

M SR 3.3.1.6

_> 56.9 Hz 57 Hz RCPs SR 3.3.1.10

14.

Steam 1,2 3 per SG E

SR 3.3.1.1

Ž> 27.6%

28%

Generator (SG)

SR 3.3.1.7 Water Level -

SR 3.3.1.10 Low Low SR 3.3.1.14 (f)

Above the P-7 (Low Power Reactor Trips Block) interlock.

Farley Units 1 and 2 3.3.1-17 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 5 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL I SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

15.

Turbine Trip

a.

Low Auto Stop 1IW 3

P SR 3.3.1.10

>43 psig 45 psig Oil Pressure SR 3.3.1.13

b. Turbine Throttle 1 (i) 4 Q

SR 3.3.1.10 NA NA Valve Closure SR 3.3.1.13

16.

Safety Injection (SI) 1,2 2 trains R

SR 3.3.1.12 NA NA Input from Engineered Safety Feature Actuation System (ESFAS)

17.

Reactor Trip System Interlocks

a.

Intermediate 2 (d) 2 T

SR 3.3.1.10 6 6E-1I amp 1E-10 amp Range Neutron SR 3.3.1.11 Flux, P-6

b.

Low Power 1

1 per train U

NA NA NA Reactor Trips Block, P-7

c.

Power Range 1

4 U

SR 3.3.1.10

_30.4% RTP 30% RTP Neutron Flux, SR 3.3.1.11 P-8

d.

Power Range 1

4 U

SR 3.3.1.10

<50.4% RTP 50% RTP Neutron Flux, SR 3.3.1.11 P-9

e.

Power Range 1,2 4

T SR 3.3.1.10 7.6% RTP 8% RTP Neutron Flux, SR 3.3.1.11 and and P-10

< 10.4% RTP 10% RTP I

f.

Turbine Impulse 1

2 U

SR 3.3.1.1

• _ 11%

10%

Pressure, P-13 SR 3.3.1.10 turbine turbine SR 3.3.1.11 power power (d)

Below the P-6 (Intermediate Range Neutron Flux) interlocks.

(i)

Above the P-9 (Power Range Neutron Flux) interlock.

Farley Units 1 and 2 3.3.1-18 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 6 of 8)

Reactor Trip System Instrumentation APPLICABLE MODES OR OTHER NOMINAL I SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

18.

Reactor Trip 1,2 2 trains S, W SR 3.3.1.4 NA NA Breakers (i) 3 (a) 4 (a) 5 (a) 2 trains C. W SR 3.3.1.4 NA NA

19.

Reactor Trip 1,2 1 each per V

SR 3.3.1.4 NA NA Breaker RTB Undervoltage and 3 (a), 4 (a), 5 (a)

C SR 3.3.1.4 NA NA Shunt Trip 1 each per Mechanisms RTB

20.

Automatic Trip 1,2 2 trains R, W SR 3.3.1.5 NA NA Logic 3 (a), 4 (a), 5 (a) 2 trains C, W SR 3.3.1.5 NA NA (a)

(J)

With RTBs closed and Rod Control System capable of rod withdrawal.

Including any reactor trip bypass breaker that is racked in and closed for bypassing an RTB.

Farley Units 1 and 2 3.3.1-19 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 7 of 8)

Reactor Trip System Instrumentation Note 1: Overtemperature AT The Overtemperature AT Function Allowable Value shall not exceed the following nominal Trip Setpoint by more than 0.4% of AT span.

AT (I+TO)<AT_)K-2(I+TS (I +

5s)

(

"S (I+ IrJs) -T'I+K 3(P-P')'fl(AI)}

Where:

AT is measured loop AT, OF.

ATo is the indicated loop AT at RTP and reference Tavg, OF.

s is the Laplace transform operator, sec-'.

T is the measured loop average temperature, OF.

T' is the reference Tavg at RTP, <

• OF.

P is the measured pressurizer pressure, psig.

P' is the nominal pressurizer operating pressure =

• psig.

K,-

t1 -

• sec 4

• sec K2 = */°F T2 <

• sec T5 _

• sec K3 */psi T6 *

• sec f1(AI) is a function of the indicated difference between top and bottom detectors of the power-range nuclear ion chambers; with gains to be selected based on measured instrument response during plant startup tests such that:

f1(Al) =

• {*+

(qt-qb)}

• % of RTP

• {(qt-qb) -*}

when (qt - qb)* * % RTP when *% RTP < (qt - qb)< *% RTP when (qt - qb)> *% RTP Where qt and qb are percent RTP in the upper and lower halves of the core, respectively, and qt + qb is the total THERMAL POWER in percent RTP.

• as specified in the COLR Farley Units 1 and 2 3.3.1-20 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RTS Instrumentation 3.3.1 Table 3.3.1-1 (page 8 of 8)

Reactor Trip System Instrumentation Note 2: Overpower AT The Overpower AT Function Allowable Value shall not exceed the following nominal Trip Setpoint by more than 0.4% of AT span.

I'i* 3s rw AT (I + T4s) <AT 0 K4-K5 1'3S I +

)

(I + Ts)

I + Z'3s

'I

+

6 T

IK6 L

T 1

- Tj-1 f 2 (A 1)}

Where:

AT is measured loop AT, OF.

ATo is the indicated loop AT at RTP and reference Tvg, OF.

s is the Laplace transform operator, sec-'.

T is the measured loop average temperature, OF.

T" is the reference Tavg at RTP, <

• OF.

K4 =

• K5 = */OF for increasing Tavg K5 = */OF for decreasing Tavg K6 = */OF when T > T" K6 = */OF when T _ T" T3 Ž

• sec

=

• sec T5 <

• sec T6 _<

• sec f2(AI) = *% RTP for all Al.

• as specified in the COLR Farley Units 1 and 2 3.3.1-21 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 1 of 4)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

1.

Safety Injection

a.

Manual Initiation

b.

Automatic Actuation Logic and Actuation Relays

c.

Containment Pressure -

High 1

d.

Pressurizer Pressure -

Low 1,2,3,4 1,2,3,4 2

2 trains 1,2,3 3

B SR 3.3.2.6 C

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.8 D

SR 3.3.2.1 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9 D

SR 3.3.2.1 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9 NA NA NA NA s 4.5 psig 4.0 psig

> 1847 psig 1850 psig 3

e.

Steam Line Pressure (1) Low (2)

High Differential Pressure Between Steam Lines 1 per steam line 3 per steam line D

SR 3.3.2.1 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9 D

SR 3.3.2.1 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9 5 7 5(c) psig 5 8 5(c) psig S 112 psig 100 psig 1,2,3 I

(a)

Above the P-11 (Pressurizer Pressure) interlock.

(b)

Above the P-12 (Tavg - Low Low) interlock.

(c)

Time constants used in the lead/lag controller are t, Ž- 50 seconds and t2 < 5 seconds.

Farley Units 1 and 2 3.3.2-9 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 2 of 4)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

2.

Containment Spray

a.

Manual Initiation

b.

Automatic Actuation Logic and Actuation Relays 1,2,3,4 1,2,3.4 2

2 trains B

SR 3.3.2.6 C

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.8 E

SR 3.3.2.1 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9 NA NA NA NA

c.

Containment Pressure High - 3 1,2,3 4

< 28.3 psig 27 psig I

3.

Containment Isolation

a.

Phase A Isolation (1) Manual Initiation (2)

Automatic Actuation Logic and Actuation Relays (3)

Safety Injection

b.

Phase B Isolation 1,2,3,4 1,2,3,4 2

2 trains B

SR 3.3.2.6 C

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.8 NA NA NA NA Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

(1) Manual Initiation (2)

Automatic Actuation Logic and Actuation Relays (3)

Containment Pressure High - 3 1,2,3,4 1,2,3,4 2

2 trains B

SR 3.3.2.6 C

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.8 E

SR 3.3.2.1 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9 NA NA NA NA 1,2,3 4

5 28.3 psig 27 psig I

Farley Units 1 and 2 3.3.2-10 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 3 of 4)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

4.

Steam Line Isolation 1 per steam

a.

Manual Initiation 1,2 (d),3 (d) line F

SR 3.3.2.6 NA NA

b.

Automatic 1,2 (d),3 (d) 2 trains G

SR 3.3.2.2 NA NA Actuation Logic SR 3.3.2.3 and Actuation SR 3.3.2.8 Relays

c.

Containment 1,2 (d), 3 (d) 3 D

SR 3.3.2.1 5 17.5 psig 16.2 psig Pressure - High 2 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9

d.

Steam Line 1,2 (d), 3(b)(d) 1 per steam D

SR 3.3.2.1

_ 575(c) psig 5 8 5 (c) psig Pressure Low line SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9

e.

High Steam Flow 1,2 (d),3 (d) 2 per steam D

SR 3.3.2.1 (e)

(f) in Two Steam line SR 3.3.2.4 Lines SR 3.3.2.7 Coincident with 1,2 (d),3 (d) 1 per loop D

SR 3.3.2.1

-542.6°F 543°F Tavg - Low Low SR 3.3.2.4 SR 3.3.2.7 Above the P-12 (Tavg - Low Low) interlock.

Time constants used in the lead/lag controller are tI > 50 seconds and t2 < 5 seconds.

Except when one MSIV is closed in each steam line.

Less than or equal to a function defined as AP corresponding to 40.3% full steam flow below 20% load, AP increasing linearly from 40.3% full steam flow at 20% load to 110.3% full steam flow at 100% load.

Less than or equal to a function defined as AP corresponding to 40% full steam flow between 0% and 20% load and then a AP increasing linearly from 40% steam flow at 20% load to 110% full steam flow at 100% load.

(b)

(c)

(d)

(e)

(f)

Farley Units 1 and 2 3.3.2-11 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages ESFAS Instrumentation 3.3.2 Table 3.3.2-1 (page 4 of 4)

Engineered Safety Feature Actuation System Instrumentation APPLICABLE MODES OR OTHER NOMINAL SPECIFIED REQUIRED SURVEILLANCE ALLOWABLE TRIP FUNCTION CONDITIONS CHANNELS CONDITIONS REQUIREMENTS VALUE SETPOINT

5.

Turbine Trip and Feedwater Isolation 1,2 2 trains

a.

Automatic Actuation Logic and Actuation Relays

b.

SG Water Level -

High High (P-14)

c.

Safety Injection H

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.8 NA NA 1,2 3 per SG SR 3.3.2.1 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9 s 82.4%

82%

1 Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

6.

Auxiliary Feedwater

a.

Automatic Actuation Logic and Actuation Relays

b.

SG Water Level-Low Low

c.

Safety Injection

d.

Undervoltage Reactor Coolant Pump

e.

Trip of all Main Feedwater Pumps 1,2,3 1,2,3 2 trains 3 per SG G

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.8 D

SR 3.3.2.1 SR 3.3.2.4 SR 3.3.2.7 SR 3.3.2.9(g)

NA

>27.6%

NA 28%

Refer to Function 1 (Safety Injection) for all initiation functions and requirements.

1,2 3

I SR 3.3.2.5 SR 3.3.2.7 SR 3.3.2.9 J

SR 3.3.2.10

>_ 2640 volts 2680 volts I

1 2 per pump NA NA

7.

ESFAS Interlocks

a.

Automatic Actuation Logic and Actuation Relays

b.

Reactor Trip, P-4

c.

Pressurizer Pressure, P-11

d.

Tavg - Low Low, P-12 (Decreasing)

(Increasing) 1,2,3 1,2,3 1,2,3 1,2,3 2 trains I per train, 2 trains 3

1 per loop L

SR 3.3.2.2 SR 3.3.2.3 SR 3.3.2.8 F

SR 3.3.2.6 K

SR 3.3.2.4 SR 3.3.2.7 K

SR 3.3.2.4 SR 3.3.2.7 NA NA NA I

< 2003 psig 2000 psig I

NA

_ 542.6°F

< 545.4°F 543*F 545*F (g)

Applicable to MDAFW pumps only.

Farley Units 1 and 2 3.3.2-12 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Remote Shutdown System 3.3.4 3.3 INSTRUMENTATION 3.3.4 Remote Shutdown System LCO 3.3.4 APPLICABILITY:

The Remote Shutdown System Functions shall be OPERABLE.

MODES 1, 2, and 3.

I ACTIONS

• . I *"lr'lr--

li II--II---------------------------------------------------------

Separate Condition entry is allowed for each Function.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required A.1 Restore required Function 30 days Functions inoperable, to OPERABLE status.

B.

---

NOTE --------

B.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Not applicable to Source Range Neutron Flux AND function.

B.2 Be in MODE 4.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Required Action and associated Completion Time not met.

Farley Units 1 and 2 3.3.4-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RCS Minimum Temperature for Criticality 3.4.2 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.2 RCS Minimum Temperature for Criticality LCO 3.4.2 APPLICABILITY:

Each RCS loop average temperature (Tavg) shall be > 541OF.

MODE 1, MODE 2 with keff 1.0.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Tav9 in one or more RCS A.1 Be in MODE 3.

30 minutes loops not within limit.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.2.1 Verify RCS Tavg in each loop > 541OF.

In accordance with the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.2-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RCS Loops -MODE 3

3.4.5 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME C.

One required RCS loop C.1 Restore required RCS 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> not in operation, with Rod loop to operation.

Control System capable of rod withdrawal.

OR C.2 Place the Rod Control 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> System in a condition incapable of rod withdrawal.

D.

Two required RCS loops D.1 Place the Rod Control Immediately inoperable.

System in a condition incapable of rod OR withdrawal.

No RCS loop in AND operation.

D.2 Suspend all operations Immediately involving a reduction of RCS boron concentration.

AND D.3 Initiate action to restore Immediately one RCS loop to OPERABLE status and operation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.5.1 Verify required RCS loops are in operation.

In accordance with the Surveillance Frequency Control Program SR 3.4.5.2 Verify steam generator secondary side water levels In accordance with are > 30% (narrow range) for required RCS loops, the Surveillance Frequency Control Program (continued)

Farley Units 1 and 2 3.4.5-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RCS Loops-- MODE 3 3.4.5 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.4.5.3 Verify correct breaker alignment and indicated power In accordance with are available to the required pump that is not in the Surveillance operation.

Frequency Control Program Farley Units 1 and 2 3.4.5-3 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Pressurizer 3.4.9 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.9 Pressurizer LCO 3.4.9 The pressurizer shall be OPERABLE with:

a.

Pressurizer water level < 63.5% indicated; and

b.

Two groups of pressurizer heaters OPERABLE with the capacity of each group > 125 kW and capable of being powered from an emergency power supply.

APPLICABILITY:

MODES 1, 2, and 3.

NOTE Pressurizer water level limit does not apply during:

a.

b.

THERMAL POWER ramp > 5% RTP per minute; or THERMAL POWER step > 10% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Pressurizer water level A.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> not within limit.

AND 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> A.2 Fully insert all rods.

AND 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> A.3 Place Rod Control System in a condition incapable of rod withdrawal.

AND 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> A.4 Be in MODE 4.

B.

One required group of B.1 Restore required group of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> pressurizer heaters pressurizer heaters to inoperable.

OPERABLE status.

(continued)

Farley Units 1 and 2 3.4.9-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL.14-1385 Clean-Typed Technical Specifications Pages Pressurizer 3.4.9 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C.

Required Action and C.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition B not AND met.

C.2 Be in MODE 4.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.9.1 Verify pressurizer water level is 5 63.5% indicated.

In accordance with the Surveillance Frequency Control Program SR 3.4.9.2 Verify capacity of each required group of pressurizer In accordance with heaters is > 125 kW.

the Surveillance Frequency Control Program SR 3.4.9.3 Verify required pressurizer heaters are capable of In accordance with being powered from an emergency power supply.

the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.9-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Pressurizer PORVs 3.4.11 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

LCO 3.4.11 APPLICABILITY:

Each PORV and associated block valve shall be OPERABLE.

MODES 1, 2, and 3.

ACTIONS

---

NOTE Separate Condition entry is allowed for each PORV and each block valve.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more PORVs A.1 Close and maintain 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> inoperable and capable of power to associated being manually cycled, block valve.

B.

One PORV inoperable and B.1 Close associated block 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> not capable of being valve.

manually cycled.

AND B.2 Remove power from 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> associated block valve.

AND B.3 Restore PORV to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> OPERABLE status.

Farley Units 1 and 2 3.4.11-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Pressurizer PORVs 3.4.11 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME F.

Two block valves F.1 Restore one block valve to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> inoperable.

OPERABLE status.

G.

Required Action and G.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition F not AND met.

G.2 Be in MODE 4.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.11.1

---

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

1. Not required to be performed with block valve closed in accordance with the Required Actions of this LCO.

2. Only required to be performed in MODES 1 and 2.

Perform a complete cycle of each block valve.

In accordance with the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.11-3 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages LTOP System 3.4.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.12.1 Verify a maximum of one charging pump is In accordance with capable of injecting into the RCS when one or more the Surveillance RCS cold legs is 5 1800F.

Frequency Control Program SR 3.4.12.2 Verify a maximum of two charging pumps are In accordance with capable of injecting into the RCS when all RCS cold the Surveillance legs are > 1800F.

Frequency Control Program SR 3.4.12.3 Verify each accumulator is isolated.

In accordance with the Surveillance Frequency Control Program SR 3.4.12.4 Verify RHR suction isolation valves are open for each In accordance with required RHR suction relief valve, the Surveillance Frequency Control Program SR 3.4.12.5

---

NOTE Only required to be met when complying with LCO 3.4.12.b.

Verify RCS vent > 2.85 square inches open.

In accordance with the Surveillance Frequency Control Program SR 3.4.12.6 Verify each required RHR suction relief valve In accordance with setpoint.

the Inservice Testing Program AND In accordance with the Surveillance Frequency Control Program Farley Units 1 and 2 3.4.12-4 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages ECCS -

Operating 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS-Operating LCO 3.5.2 Two ECCS trains shall be OPERABLE.

---

II-j r-n ---------------------------------------------

1.

In MODE 3, the Residual Heat Removal or the Centrifugal Charging Pump flow paths may be isolated by closing the isolation valves for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> to perform pressure isolation valve testing per SR 3.4.14.1.

2.

Upon entry into MODE 3 from MODE 4, the breaker or disconnect device to the valve operators for MOVs 8706A and 8706B may be locked open for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> to allow for repositioning from MODE 4 requirements.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more trains A.1 Restore train(s) to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable.

OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met.

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> C.

Less than 100% of the C.1 Enter LCO 3.0.3.

Immediately ECCS flow equivalent to a single OPERABLE ECCS train available.

Farley Units 1 and 2 3.5.2-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Seal Injection Flow 3.5.5 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.5 Seal Injection Flow LCO 3.5.5 Reactor coolant pump seal injection flow shall be within limits.

APPLICABILITY:

MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Seal injection flow not A.1 Adjust manual seal 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> within limit, injection throttle valves in accordance with SR 3.5.5.1.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time not met.

AND B.2 Be in MODE 4.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Farley Units 1 and 2 3.5.5-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Seal Injection Flow 3.5.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.5.5.1 NOTE---------------

Not required to be performed until 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the Reactor Coolant System pressure stabilizes at

_ 2215 psig and _ 2255 psig.

Verify manual seal injection throttle valves are In accordance with adjusted to give a flow within the limits of Figure the Surveillance 3.5.5-1 with the seal water injection flow control Frequency Control valve full open.

Program I

Farley Units 1 and 2 3.5.5-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Containment Isolation Valves 3.6.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.6.3.3

---

NOTES

1.

Valves and blind flanges in high radiation areas may be verified by use of administrative means.

2.

The blind flange on the fuel transfer canal flange is only required to be verified closed after each draining of the canal.

Verify each containment isolation manual valve and Prior to entering blind flange that is located inside containment and MODE 4 from not locked, sealed, or otherwise secured and MODE 5 if not required to be closed during accident conditions is performed within closed, except for containment isolation valves that the previous are open under administrative controls.

92 days SR 3.6.3.4 Verify the isolation time of each automatic power In accordance with operated containment isolation valve in the IST the Inservice Program is within limits.

Testing Program SR 3.6.3.5 Perform leakage rate testing for containment In accordance with penetrations containing containment purge valves the Surveillance with resilient seals.

Frequency Control Program AND Within 92 days after opening the valve SR 3.6.3.6 Verify each automatic containment isolation valve In accordance with that is not locked, sealed or otherwise secured in the Surveillance position, actuates to the isolation position on an Frequency Control actual or simulated actuation signal.

Program Farley Units 1 and 2 3.6.3-6 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Containment Spray and Cooling Systems 3.6.6 3.6 CONTAINMENT SYSTEMS 3.6.6 Containment Spray and Cooling Systems LCO 3.6.6 Two containment spray trains and two containment cooling trains shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One containment spray A.1 Restore containment 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> train inoperable, spray train to OPERABLE status.

B.

Required Action and B.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5.

84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br /> C.

One containment cooling C.1 Restore containment 7 days train inoperable, cooling train to OPERABLE status.

I Farley Units 1 and 2 3.6.6-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages 3.7 PLANT SYSTEMS 3.7.5 Auxiliary Feedwater (AFW) System AFW System 3.7.5 LCO 3.7.5 APPLICABILITY:

Three AFW trains shall be OPERABLE.

MODES 1, 2, and 3.

ACTIONS NOTE-LCO 3.0.4b is not applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A.

One steam supply to A.1 Restore affected equipment 7 days turbine driven AFW pump to OPERABLE status.

inoperable.

OR

-NOTE Only applicable if MODE 2 has not been entered following refueling.

One turbine driven AFW pump inoperable in MODE 3 following refueling.

B.

One AFW train B.1 Restore AFW train to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> inoperable for reasons OPERABLE status.

other than Condition A.

Farley Units 1 and 2 3.7.5-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages AFW System 3.7.5 ACTIONS (continued).

CONDITION REQUIRED ACTION COMPLETION TIME C.

Required Action and C.1 Be in MODE 3.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time for Condition A or B AND not met.

C.2 Be in MODE 4.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> OR Two AFW trains inoperable.

D.

Three AFW trains D.1

---

NOTE inoperable.

LCO 3.0.3 and all other LCO Required Actions requiring MODE changes are suspended until one AFW train is restored to OPERABLE status.

Initiate action to restore Immediately one AFW train to OPERABLE status.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.1

---

NOTE AFW train(s) may be considered OPERABLE during alignment and operation for steam generator level control, if it is capable of being manually realigned to the AFW mode of operation.

Verify each AFW manual, power operated, and In accordance automatic valve in each water flow path, and in both with the steam supply flow paths to the steam turbine driven Surveillance pump, that is not locked, sealed, or otherwise Frequency secured in position, is in the correct position.

Control Program Farley Units 1 and 2 3.7.5-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages AFW System 3.7.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.7.5.2

---

NOTE Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after ?_ 1005 psig in the steam generator.

Verify the developed head of each AFW pump at the In accordance flow test point is greater than or equal to the required with the Inservice developed head.

Testing Program.

SR 3.7.5.3

---

NOTE In accordance AFW train(s) may be considered OPERABLE during with the alignment and operation for steam generator level Surveillance control, if it is capable of being manually realigned to Frequency the AFW mode of operation.

Control Program Verify each AFW automatic valve that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

SR 3.7.5.4

---

NOTES

1. Not required to be performed for the turbine driven AFW pump until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after >_ 1005 psig in the steam generator.

2. AFW train(s) may be considered OPERABLE In accordance during alignment and operation for steam with the generator level control, if it is capable of being Surveillance manually realigned to the AFW mode of Frequency operation.

Control Program Verify each AFW pump starts automatically on an actual or simulated actuation signal.

SR 3.7.5.5 Verify the turbine driven AFW pump steam admission In accordance valves open when air is supplied from their respective with the air accumulators.

Surveillance Frequency Control Program Farley Units 1 and 2 3.7.5-3 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages AC Sources -

Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

(continued)

A.3 Restore required offsite 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> circuit to OPERABLE status.

B.

One DG set inoperable.

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

LCO 3.0.4c is applicable when only one of the three DGs is inoperable.

B.1 AND B.2 AND B.3.1 Perform SR 3.8.1.1 for the required offsite circuit(s).

Declare required feature(s) supported by the inoperable DG set inoperable when its required redundant feature(s) is inoperable.

Determine OPERABLE DG set is not inoperable due to common cause failure.

2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> AND Once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> from discovery of Condition B concurrent with inoperability of redundant required feature(s) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OR (continued)

Farley Units 1 and 2 3.8.1-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages AC Sources - Operating 3.8.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B.

(continued)

B.3.2 Perform SR 3.8.1.6 for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> OPERABLE DG set.

AND B.4 Restore DG set to 10 days OPERABLE status.

C.

Two required offsite C.1 Declare required 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> from circuits inoperable, feature(s) inoperable discovery of when its redundant Condition C required feature(s) is concurrent with inoperable.

inoperability of redundant required features AND C.2 Restore one required 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> offsite circuit to OPERABLE status.

Farley Units 1 and 2 3.8.1-3 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages AC Sources -

Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.7 NOTE --------------------------------

This Surveillance shall not normally be performed in MODE 1 or 2. However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify manual transfer of AC power sources from the normal offsite circuit to the alternate required offsite circuit.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.8 Verify each DG rejects a load greater than or equal to In accordance with its associated single largest post-accident load, and:

the Surveillance

a.

Following load rejection, the speed is < 75% of Frequency Control the difference between nominal speed and the Program overspeed trip setpoint; and

b.

Following load rejection, the voltage is

> 3740 V and 5 4580 V.

Farley Units 1 and 2 3.8.1-8 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages AC Sources -

Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.9

---

NOTES

1.

All DG starts may be preceded by an engine prelube period.

2.

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify on an actual or simulated loss of offsite power signal:

a.

De-energization of emergency buses;

b.

Load shedding from emergency buses;

c.

DG auto-starts from standby condition and:

1.

energizes permanently connected loads in < 12 seconds,

2.

energizes auto-connected shutdown loads through automatic load sequencer,

3.

maintains steady state voltage

> 3740 V and*< 4580 V,

4.

maintains steady state frequency

> 58.8 Hz and

• 61.2 Hz, and

5.

supplies permanently connected and auto-connected shutdown loads for

_> 5 minutes.

In accordance with the Surveillance Frequency Control Program Farley Units 1 and 2 3.8.1-9 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages AC Sources -

Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.13 NOTES ---------------

1.

This Surveillance shall be performed within 10 minutes of shutting down the DG after the DG has operated >_ 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> loaded > 4075 kW for the 4075 kW DGs and _> 2850 kW for the 2850 kW DG.

Momentary transients below the minimum load specified do not invalidate this test.

2.

All DG starts may be preceded by an engine prelube period.

Verify each DG starts and achieves, in 5 12 seconds, voltage > 3952 V and frequency > 60 Hz.

In accordance with the Surveillance Frequency Control Program SR 3.8.1.14 NOTE ---------------

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify each DG:

a.

Synchronizes with offsite power source while loaded with emergency loads upon a simulated restoration of offsite power;

b.

Transfers loads to offsite power source; and

c.

Returns to ready-to-load operation.

In accordance with the Surveillance Frequency Control Program Farley Units 1 and 2 3.8.1-12 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages AC Sources -

Operating 3.8.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.15 Verify, with a DG operating in test mode and In accordance with connected to its bus, an actual or simulated ESF the Surveillance actuation signal overrides the test mode by returning Frequency Control DG to ready-to-load operation.

Program SR 3.8.1.16 Verify interval between each sequenced load block is In accordance with within +/- 10% of design interval or 0.5 seconds, the Surveillance whichever is greater, for each emergency load Frequency Control sequencer.

Program SR 3.8.1.17

---

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

1.

All DG starts may be preceded by an engine prelube period.

2.

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, portions of the surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the plant is maintained or enhanced.

Verify on an actual or simulated loss of offsite power In accordance with signal in conjunction with an actual or simulated ESF the Surveillance actuation signal:

Frequency Control

a.

De-energization of emergency buses; Program

b.

Load shedding from emergency buses; and

c.

DG auto-starts from standby condition and:

1.

energizes permanently connected loads in < 12 seconds, (continued)

Farley Units 1 and 2 3.8.1-13 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Distribution Systems -

Operating 3,8.9 3.8 ELECTRICAL POWER SYSTEMS 3.8.9 Distribution Systems -

Operating LCO 3.8.9 APPLICABILITY:

Train A and Train B AC, DC, and AC vital bus electrical power distribution subsystems shall be OPERABLE.

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more AC electrical A.1 Restore AC electrical 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> power distribution power distribution subsystems inoperable, subsystem(s) to OPERABLE status.

B.

One or more AC vital B.1 Restore AC vital bus 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> buses inoperable, subsystem(s) to OPERABLE status.

C.

One Auxiliary Building DC C.1 Restore Auxiliary 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> electrical power distribution Building DC electrical subsystem inoperable, power distribution subsystem to OPERABLE status.

Farley Units 1 and 2 3.8.9-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Boron Concentration 3.9.1 3.9 REFUELING OPERATIONS 3.9.1 Boron Concentration LCO 3.9.1 APPLICABILITY:

Boron concentrations of the Reactor Coolant System, the refueling canal, and the refueling cavity shall be maintained within the limit specified in the COLR.

MODE 6.

NOTE Only applicable to the refueling canal and refueling cavity when connected to the RCS.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Boron concentration not A.1 Suspend CORE Immediately within limit.

ALTERATIONS.

AND A.2 Suspend positive Immediately reactivity additions.

AND A.3 Initiate action to restore Immediately boron concentration to within limit.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.1.1 Verify boron concentration is within the limit specified In accordance with in COLR.

the Surveillance Frequency Control Program Farley Units 1 and 2 3.9.1-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Containment Penetrations 3.9.3 3.9 REFUELING OPERATIONS 3.9.3 Containment Penetrations LCO 3.9.3 The containment penetrations shall be in the following status:

a.

The equipment hatch is capable of being closed and held in place by four bolts;

b.

One door in each air lock is capable of being closed; and

c.

Each penetration providing direct access from the containment atmosphere to the outside atmosphere either:

1.

closed by a manual or automatic isolation valve, blind flange, or equivalent, or

2.

capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System.

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

Penetration flow path(s) providing direct access from the containment atmosphere to the outside atmosphere may be unisolated under administrative controls.

APPLICABILITY:

During CORE ALTERATIONS, During movement of irradiated fuel assemblies within containment.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more containment A.1 Suspend CORE Immediately penetrations not in ALTERATIONS.

required status.

AND A.2 Suspend movement of Immediately irradiated fuel assemblies within containment.

Farley Units 1 and 2 3.9.3-1 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Containment Penetrations 3.9.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.9.3.1 Verify each required containment penetration is in the In accordance required status.

with the Surveillance Frequency Control Program SR 3.9.3.2 NOTE In accordance Not required to be met for containment purge and with the exhaust valve(s) in penetrations closed to comply Surveillance with LCO 3.9.3.c.1.

Frequency Control Program Verify each required containment purge and exhaust valve actuates to the isolation position on an actual or simulated actuation signal.

SR 3.9.3.3

---

NOTE In accordance Only required for an open equipment hatch, with the Surveillance Verify the capability to install the equipment Frequency Control hatch.

Program Farley Units 1 and 2 3.9.3-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RHR and Coolant Circulation -

Low Water Level 3.9.5 3.9 REFUELING OPERATIONS 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation -

Low Water Level LCO 3.9.5 Two RHR loops shall be OPERABLE, and one RHR loop shall be in operation.

NOTES

1.

One RHR loop may be inoperable and no RHR loop may be in the decay heat removal mode of operation for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for required surveillance testing.

2.

All RHR pumps may be de-energized for < 15 minutes when switching from one train to another provided:

a. The core outlet temperature is maintained > 10 degrees F below saturation temperature.

b.

No operations are permitted that would cause a reduction of the Reactor Coolant System (RCS) boron concentration; and

c. No draining operations to further reduce RCS water volume are permitted.

APPLICABILITY:

MODE 6 with the water level < 23 ft above the top of reactor vessel flange.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Less than the required A.1 Initiate action to restore Immediately number of RHR loops required RHR loops to OPERABLE.

OPERABLE status.

OR A.2 Initiate action to Immediately establish > 23 ft of water above the top of reactor vessel flange.

(continued)

Farley Units 1 and 2 3.9.5-1 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages RHR and Coolant Circulation -

Low Water Level 3.9.5 ACTIONS (continued)

CONDITION I

REQUIRED ACTION COMPLETION TIME B.

No RHR loop in operation. I B.1 Suspend operations involving a reduction in reactor coolant boron concentration.

AND B.2 Initiate action to restore one RHR loop to operation.

AND I,

~

D.0 AND B.4 Close equipment hatch and secure with four bolts.

Close one door in each air lock.

Immediately Immediately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 4 hours 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 4 hours AND B.5.1 Close each penetration providing direct access from the containment atmosphere to the outside atmosphere with a manual or automatic isolation valve, blind flange, or equivalent.

OR B.5.2 Verify each penetration is capable of being closed by an OPERABLE Containment Purge and Exhaust Isolation System.

Farley Units 1 and 2 3.9.5-2 Amendment No.

Amendment No.

(Unit 1)

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.4 Radioactive Effluent Controls Program (continued)

b.

Limitations on the concentrations of radioactive material released in liquid effluents to unrestricted areas, conforming to 10 times the concentration stated in 10 CFR 20, Appendix B (to paragraphs 20.1001-20.2401),

Table 2, Column 2;

c.

Monitoring, sampling, and analysis of radioactive liquid and gaseous effluents in accordance with 10 CFR 20.1302 and with the methodology and parameters in the ODCM;

d.

Limitations on the annual and quarterly doses or dose commitment to a member of the public from radioactive materials in liquid effluents released from each unit to unrestricted areas, conforming to 10 CFR 50, Appendix I;

e.

Determination of cumulative dose contributions from radioactive effluents for the current calendar quarter and current calendar year in accordance with the methodology and parameters in the ODCM at least every 31 days.

Determination of projected dose contributions from radioactive effluents in accordance with the methodology in the ODCM at least every 31 days.

f.

Limitations on the functional capability and use of the liquid and gaseous effluent treatment systems to ensure that appropriate portions of these systems are used to reduce releases of radioactivity when the projected doses in a period of 31 days would exceed 2% of the guidelines for the annual dose or dose commitment, conforming to 10 CFR 50, Appendix I;

g.

Limitations on the dose rate resulting from radioactive material released in gaseous effluents to areas at and beyond the site boundary as follows:

1.

For noble gases: Less than or equal to a dose rate of 500 mrem/year to the total body and less than or equal to a dose rate of 3000 mrem/year to the skin, and

2.

For lodine-131, lodine-133, tritium, and for all radionuclides in particulate form with half lives greater than 8 days: Less than or equal to a dose rate of 1500 mrem/year to any organ.

h.

Limitations on the annual and quarterly air doses resulting from noble gases released in gaseous effluents from each unit to areas beyond the site boundary, conforming to 10 CFR 50, Appendix 1; (continued)

Farley Units 1 and 2 5.5-3 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)

b.

Provisions for ensuring the plant is maintained in a safe condition if a loss of function condition exists;

c.

Provisions to ensure that an inoperable supported system's Completion Time is not inappropriately extended as a result of multiple support system inoperabilities; and

d.

Other appropriate limitations and remedial or compensatory actions.

A loss of safety function exists when, assuming no concurrent single failure, no concurrent loss of offsite power or no concurrent loss of onsite diesel generator(s), a safety function assumed in the accident analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a.

A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b.

A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

c.

A required system redundant to the support system(s) for the supported systems (a) and (b) above is also inoperable.

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.16 Main Steamline Inspection Program The three main steamlines from the rigid anchor points of the containment penetrations downstream to and including the main steam header shall be inspected. The extent of the inservice examinations completed during each inspection interval (IWA 2400, ASME Code, 1974 Edition,Section XI) shall provide 100 percent volumetric examination of circumferential and longitudinal pipe welds to the extent practical. The areas subject to examination are those defined in accordance with examination category C-G for Class 2 piping welds in Table IWC-2520.

(continued)

Farley Units 1 and 2 5.5-13 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.17 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of containment as required by 10 CFR 50.54 (o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September 1995, as modified by the following exception to NEI 94-01, Rev. 0, "Industry Guidelines for Implementing Performance-Based Option of 10 CFR 50, Appendix J":

1.

The visual examination of containment concrete surfaces intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B testing, will be performed in accordance with the requirements of frequency specified by the ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC.

2.

The visual examination of the steel liner plate inside containment intended to fulfill the requirements of 10 CFR 50, Appendix J, Option B, will be performed in accordance with the requirements of and frequency specified by the ASME Section XI Code, Subsection IWE, except where relief has been authorized by the NRC.

The peak calculated containment internal pressure for the design basis loss of coolant accident, Pa, is 43.8 psig.

The maximum allowable containment leakage rate, La, at Pa, is 0.15% of containment air weight per day.

Leakage rate acceptance criteria are:

a.

Containment overall leakage rate acceptance criterion is _< 1.0 La. During plant startup following testing in accordance with this program, the leakage rate acceptance criteria are '_ 0.60 La for the combined Type B and C tests, and _< 0.75 La for Type A tests;

b.

Air lock testing acceptance criteria are:

1.

Overall air lock leakage rate is _< 0.05 La when tested at >_ Pa.

2.

For each door, leakage rate is _ 0.01 La when pressurized to _> 10 psig.

c.

During plant startup following testing in accordance with this program, the leakage rate acceptance criterion for each containment purge penetration flowpath is _< 0.05 La.

(continued)

Farley Units 1 and 2 5.5-14 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.17 Containment Leakage Rate Testing Program (continued)

The provisions of SR 3.0.2 do not apply to the test frequencies specified in the Containment Leakage Rate Testing Program.

The provisions of SR 3.0.3 are applicable to the Containment Leakage Rate Testing Program.

5.5.18 Control Room Integrity Program (CRIP)

A Control Room Integrity Program (CRIP) shall be established and implemented to ensure that the control room integrity is maintained such that a radiological event, hazardous chemicals, or a fire challenge (e.g., fire byproducts, halon, etc.)

will not prevent the control room operators from controlling the reactor during normal or accident conditions. The program shall require testing as outlined below. Testing should be performed when changes are made to structures, systems and components which could impact Control Room Impact (CRE) integrity. These structures, systems and components may be internal or external to the CRE. Testing should also be conducted following a modification or a repair that could affect CRE inleakage. Testing should also be performed if the conditions associated with a particular challenge result in a change in operating mode, system alignment or system response that could result in a new limiting condition. Testing should be commensurate with the type and degree of modification or repair. Testing should be conducted in the alignment that results in the greatest consequence to the operators.

A CRIP shall be established to implement the following:

a.

Demonstrate, using Regulatory Guide (RG) 1.197 and ASTM E741, that CRE inleakage is less than the below values. The values listed below do not include 10 cfm assumed in accident analysis for ingress / egress.

i) 43 cfm when the control room ventilation systems are aligned in the emergency recirculation mode of operation, ii) 600 cfm when the control room ventilation systems are aligned in the isolation mode of operation, and iii) 2,340 cfm when the control room ventilation systems are aligned in the normal mode of operation;

b.

Demonstrate that the leakage characteristics of the CRE will not result in simultaneous loss of reactor control capability from the control room and the hot shutdown panels; (continued)

Farley Units 1 and 2 5.5-15 Amendment No.

(Unit 1)

Amendment No.

(Unit 2) to NL-14-1385 Clean-Typed Technical Specifications Pages Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.18 Control Room Integrity Program (CRIP) (continued)

c.

Maintain a CRE configuration control and a design and licensing bases control program and a preventative maintenance program. As a minimum, the CRE configuration control program will determine whether the i) CRE differential pressure relative to adjacent areas and ii) the control room ventilation system flow rates, as determined in accordance with ASME N510-1989 or ASTM E2029-99, are consistent with the values measured at the time the ASTM E741 test was performed. If item i or ii has changed, determine how this change has affected the inleakage characteristics of the CRE. If there has been degradation in the inleakage characteristics of the CRE since the E741 test, then a determination should be made whether the licensing basis analyses remain valid. If the licensing basis analyses remain valid, the CRE remains OPERABLE.

d.

Test the CRE in accordance with the testing methods and at the frequencies specified in RG 1.197, Revision 0, May 2003.

The provisions of SR 3.0.2 are applicable to the control room inleakage testing frequencies.

5.5.19 Surveillance Frequency Control Program This program provides controls for Surveillance Frequencies. The program shall ensure that Surveillance Requirements specified in the Technical Specifications are performed at intervals sufficient to assure the associated Limiting Conditions for Operation are met.

a.

The Surveillance Frequency Control Program shall contain a list of Frequencies of those Surveillance Requirements for which the Frequency is controlled by the program.

b.

Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1.

c.

The provisions of Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.

Farley Units 1 and 2 5.5-16 Amendment No.

(Unit 1)

Amendment No.

(Unit 2)

Joseph M. Farley Nuclear Plant - Units 1 and 2 Request for Technical Specification Amendment Adoption of Previously NRC-Approved Generic Technical Specification Changes and Other Changes Summary of Regulatory Commitments Summary of Regulatory Commitments The following table identifies the regulatory commitments in this document. Any other statements in this submittal represent intended or planned actions. They are provided for information purposes and are not considered to be regulatory commitments.

REGULATORY COMMITMENTS DUE DATE / EVENT

1. Administrative controls will be established to ensure Prior to appropriate personnel are aware of the open status of the implementation of penetration flow path(s) during core alterations or movement of the LAR.

irradiated fuel assemblies within the containment.

2. Existing administrative controls for open containment airlock Prior to doors will be expanded to ensure specified individuals are implementation of designated and readily available to isolate any open the LAR.

penetration flow path(s) in the event of an FHA inside containment.

3. SNC commits to revise Operations procedure FNP-0-SOP-0. 13 Prior to to include a statement similar to the following: "Alternating implementation of between LCO Conditions, in order to allow indefinite continued the LAR.

operation while not meeting the LCO, is not allowed."

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