ML042580071

Amendment Nos. 163 and 156 Technical Specifications

ML042580071
Person / Time
Site:	Farley
Issue date:	09/10/2004
From:	NRC/NRR/DLPM
To:	Southern Nuclear Operating Co
Peters S, NRR/DLPM, 415-1842
Shared Package
ML042570427	List: ML042570418 ML042580071
References
NEI 97-08, TAC MC3667, TAC MC3668
Download: ML042580071 (34)

Text

TABLE OF CONTENTS 3.4 REACTOR COOLANT SYSTEM (RCS) ................................................. 3.4.1-1 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits ................................................. 3.4.1-1 3.4.2 RCS Minimum Temperature for Criticality ....................................... 3.4.2-1 3.4.3 RCS Pressure and Temperature (P/T) Limits ................................. 3.4.3-1 3.4.4 RCS Loops-MODES 1 and 2 ................................................. 3.4.4-1 3.4.5 RCS Loops-MODE 3 ................................................. 3.4.5-1 3.4.6 RCS Loops-MODE 4 ................................................. 3.4.6-1 3.4.7 RCS Loops-MODE 5, Loops Filled .............................................. 3.4.7-1 3.4.8 RCS Loops-MODE 5, Loops Not Filled ....................................... 3.4.8-1 3.4.9 Pressurizer ................................................. 3.4.9-1 3.4.10 Pressurizer Safety Valves ................................................. 3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) ...................... 3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP) System........... 3.4.12-1 3.4.13 RCS Operational LEAKAGE ................................................. 3.4.13-1 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage ................................. 3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation ........................................ 3.4.15-1 3.4.16 RCS Specific Activity ................................................. 3.4.16-1 3.4.17 Steam Generator (SG) Tube Integrity ............................................. 3.4.17-1 l 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) ............................. 3.5.1-1 3.5.1 Accumulators ................................................. 3.5.1-1 3.5.2 ECCS-Operating ................................................. 3.5.2-1 3.5.3 ECCS-Shutdown ................................................. 3.5.3-1 3.5.4 Refueling Water Storage Tank (RWST) ......................................... 3.5.4-1 3.5.5 Seal Injection Flow ................................................. 3.5.5-1 3.5.6 ECCS Recirculation Fluid pH Control System ................................. 3.5.6-1 3.6 CONTAINMENT SYSTEMS ................................................. 3.6.1-1 3.6.1 Containment ................................................. 3.6.1-1 3.6.2 Containment Air Locks ................................................. 3.6.2-1 3.6.3 Containment Isolation Valves ................................................. 3.6.3-1 3.6.4 Containment Pressure ................................................. 3.6.4-1 3.6.5 Containment Air Temperature ................................................. 3.6.5-1 3.6.6 Containment Spray and Cooling Systems ...................................... 3.6.6-1 3.6.7 Hydrogen Recombiners ................................................. 3.6.7-1 3.6.8 Hydrogen Mixing System (HMS) ................................................. 3.6.8-1 3.6.9 Reactor Cavity Hydrogen Dilution System ..................................... 3.6.9-1 3.7 PLANT SYSTEMS ................................................. 3.7.1-1 3.7.1 Main Steam Safety Valves (MSSVs) ............................................... 3.7.1-1 3.7.2 Main Steam Isolation Valves (MSIVs) ............................................. 3.7.2-1 Farley Units 1 and 2 ii Amendment No. 163 (Unit 1)

Amendment No. 156 (Unit 2)

RCS Operational LEAKAGE 3.4.13 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.13 RCS Operational LEAKAGE LCO 3.4.13 RCS operational LEAKAGE shall be limited to:

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG).

APPLICABILITY: MODES 1,2,3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. RCS operational A.1 Reduce LEAKAGE to 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br /> LEAKAGE not within limits within limits.

I for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.

B. Required Action and B.1 Be in MODE 3. 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours1.5 days <br />0.214 weeks <br />0.0493 months <br /> OR Pressure boundary LEAKAGE exists.

OR Primary to secondary LEAKAGE not within limit.

Farley Units 1 and 2 3.4.13-1 Amendment No. 163(Unit 1)

Amendment No. 156 (Unit 2)

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1 ------------------------------- NOTES--------------------------- -------NOTE--------

1. Not required to be performed in MODE 3 or 4 Only required to until 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> of steady state operation. be performed during steady

2. Not applicable to primary to secondary LEAKAGE. state operation Verify RCS operational LEAKAGE is within limits by performance of RCS water inventory balance. 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> SR 3.4.13.2 ---------------------------------- NOTE--------------------------

Not required to be performed until 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> after establishment of steady state operation.

Verify primary to secondary LEAKAGE is

• 150 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> gallons per day through any one SG.

Farley Units 1 and 2 3.4.13-2 Amendment No.l 6 3 (Unit 1)

Amendment No.156 (Unit 2)

SG Tube Integrity 3.4.17 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.17 Steam Generator (SG) Tube Integrity LCO 3.4.17 SG tube integrity shall be maintained.

AND All SG tubes satisfying the tube repair criteria shall be plugged in accordance with the Steam Generator Program.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS

-- --------------------------- NO t--------------- ---- ---- -__________________-

Separate Condition entry is allowed for each SG tube.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more SG tubes A.1 Verify tube integrity of the 7 days satisfying the tube repair affected tube(s) is criteria and not plugged maintained until the next in accordance with the inspection.

Steam Generator AND Program.

A.2 Plug the affected tube(s) Prior to entering in accordance with the MODE 4 following Steam Generator the next refueling Program. outage or SG tube inspection B. Required Action and B.1 Be in MODE 3. 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours1.5 days <br />0.214 weeks <br />0.0493 months <br /> OR SG tube integrity not maintained.

Farley Units 1 and 2 3.4.17-1 Amendment No. 163 (Unit 1)

Amendment No.156 (Unit 2)

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.17.1 Verify SG tube integrity in accordance with the In accordance with Steam Generator Program. the Steam Generator Program SR 3.4.17.2 Verify that each inspected SG tube that satisfies the Prior to entering tube repair criteria is plugged in accordance with the MODE 4 following Steam Generator Program. a SG tube inspection Farley Units 1 and 2 3.4.17-2 Amendment No. 163 (Unit 1)

Amendment No. 156 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Inservice Testing Program This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components. The program shall include the following:

a. Testing frequencies specified in Section Xl of the ASME Boiler and Pressure Vessel Code and applicable Addenda as follows:

ASME Boiler and Pressure Vessel Code and applicable Addenda terminology for Required Frequencies inservice testing for performing inservice activities testing activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

b. The provisions of SR 3.0.2 are applicable to the above required Frequencies for performing inservice testing activities;

c. The provisions of SR 3.0.3 are applicable to inservice testing activities; and

d. Nothing in the ASME Boiler and Pressure Vessel Code shall be construed to supersede the requirements of any TS.

5.5.9 Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice (continued)

Farley Units 1 and 2 5.5-5 Amendment No. 163 (Unit 1)

Amendment No. 156 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Program (continued) inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

b. Performance criteria for SG tube integrity. SG tube integrity shall be maintained by meeting the performance criteria for tube structural integrity, accident induced leakage, and operational LEAKAGE.

1. Structural integrity performance criterion: All inservice SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby and cooldown and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 (3AP) against burst under normal steady state full power operation primary to secondary pressure differential and a safety factor of 1.4 against burst applied to the design basis accident primary to secondary pressure differentials. Apart from the above requirements, additional loading conditions associated with the design basis accidents, or combination of accidents in accordance with the design and licensing basis, shall also be evaluated to determine if the associated loads contribute significantly to burst or collapse. In the assessment of tube integrity, those loads that do significantly affect burst or collapse shall be determined and assessed in combination with the loads due to pressure with a safety factor of 1.2 on the combined primary loads and 1.0 on axial secondary loads.

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG tube rupture, shall not exceed the leakage rate assumed in the accident analysis in terms of total leakage rate for all SGs and leakage rate for an individual SG. Accident induced leakage is not to exceed 1 gpm total for all three SGs.

3. The operational LEAKAGE performance criterion is specified in LCO 3.4.13, "RCS Operational LEAKAGE."

(continued)

Farley Units 1 and 2 5.5-6 Amendment No.163 (Unit 1)

Amendment No.156 (Unit 2)

l Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator SG Program (continued)

c. Provisions for SG tube repair criteria. Tubes found by inservice inspection to contain flaws with a depth equal to or exceeding 40% of the nominal tube wall thickness shall be plugged.

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and methods of inspection shall be performed with the objective of detecting flaws of any type (e.g., volumetric flaws, axial and circumferential cracks) that may be present along the length of the tube, from the tube-to-tubesheet weld at the tube inlet to the tube-to-tubesheet weld at the tube outlet, and that may satisfy the applicable tube repair criteria. The tube-to-tubesheet weld is not part of the tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection. An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

1. Inspect 100% of the tubes in each SG during the first refueling outage following SG replacement.

2. Inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 effective full power months. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 72 effective full power months or three refueling outages (whichever is less) without being inspected.

3. If crack indications are found in any SG tube, then the next inspection for each SG for the degradation mechanism that caused the crack indication shall not exceed 24 effective full power months or one refueling outage (whichever is less). If definitive information, such as from examination of a pulled tube, diagnostic non-destructive testing, or engineering evaluation indicates that a crack-like indication is not associated with a crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE.

Farley Units 1 and 2 5.5-7 Amendment No.163 (Unit 1)

Amendment No.15 6 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation. The program shall include:

a. Identification of a sampling schedule for the critical variables and control points for these variables;

b. Identification of the procedures used to measure the values of the critical variables;

c. Identification of process sampling points, which shall include monitoring the condenser hotwells for evidence of condenser in leakage;

d. Procedures for the recording and management of data;

e. Procedures defining corrective actions for all off control point chemistry conditions; and

f. A procedure identifying the authority responsible for the interpretation of the data and the sequence and timing of administrative events, which is required to initiate corrective action.

5.5.11 Ventilation Filter Testing Program (VFTP)

A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems at the frequencies specified in, and in accordance with, ASME N510-1989. The FNP Final Safety Analysis Report identifies the relevant surveillance testing requirements.

a. Demonstrate for each of the ESF systems that an inplace test of the high efficiency particulate air (HEPA) filters shows a penetration and system bypass < 0.5% when tested in accordance with ASME N510-1989 at the system flowrate specified below.

ESF Ventilation System Flowrate (CFM)

CREFS Recirculation 2,000 + 10%

CREFS Filtration 1,000 + 10%

CREFS Pressurization 300 + 25% to - 10%

PRF Post LOCA Mode 5,000 + 10%

(continued)

Farley Units 1 and 2 5.5-8 Amendment No163 (Unit 1)

Amendment No156 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testing Program (VFTP) (continued)

b. Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows a penetration and system bypass < 0.5% when tested in accordance ASME N510-1989 at the system flowrate specified below.

ESF Ventilation SVstem Flowrate (CFM)

CREFS Recirculation 2,000 + 10%

CREFS Filtration 1,000 + 10%

CREFS Pressurization 300 + 25% to - 10%

PRF Post LOCA Mode 5,000 + 10%

c. Demonstrate for each of the ESF systems that a laboratory test of a sample of the charcoal adsorber, when obtained as described in ASME N510-1989, shows the methyl iodide penetration less than the value specified below when tested in accordance with ASTM D3803-1989 at a temperature of < 30OC and greater than or equal to the relative humidity specified below.

ESF Ventilation System Penetration RH CREFS Recirculation 2.5% 70%

CREFS Filtration 2.5% 70%

CREFS Pressurization 0.5% 70%

PRF Post LOCA Mode 5% 95%

NOTE: CREFS Pressurization methyl iodide penetration limit is based on a 6-inch bed depth.

d. Demonstrate for each of the ESF systems that the pressure drop across the combined HEPA filters and the charcoal adsorbers is less than the value specified below when tested in accordance with ASME N510-1989 at the system flowrate specified below.

Delta P Flowrate ESF Ventilation System (in. water gauge) (CFM)

CREFS Recirculation 2.3 2,000 + 10%

CREFS Filtration 2.9 1,000 + 10%

CREFS Pressurization 2.2 300 + 25% to - 10%

PRF Post LOCA Mode 2.6 5,000 + 10%

(continued)

Farley Units 1 and 2 5.5-9 Amendment No.163 (Unit 1) l Amendment No.156 (Unit 2) l

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Ventilation Filter Testinq Program (VFTP) (continued)

e. Demonstrate that the heaters for the CREFS Pressurization System dissipate the value specified below when tested in accordance with ASME N510-1 989.

ESF Ventilation SVstem Wattage (kW)

CREFS Pressurization 2.5 + 0.5 The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

5.5.12 Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the Waste Gas System, the quantity of radioactivity contained in gas storage tanks, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks.

The program shall include:

a. The limits for concentrations of hydrogen and oxygen in the Waste Gas System and a surveillance program to ensure the limits are maintained.

Such limits shall be appropriate to the system's design;

b. A surveillance program to ensure that the quantity of radioactivity contained in each gas storage tank is less than the amount that would result in a whole body exposure of > 0.5 rem to any individual in an unrestricted area, in the event of an uncontrolled release of the tanks' contents; and

c. A surveillance program to ensure that the quantity of radioactivity contained in all outdoor liquid radwaste tanks that are not surrounded by liners, dikes, or walls, capable of holding the tanks' contents and that do not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System is less than 10 curies.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Explosive Gas and Storage Tank Radioactivity Monitoring Program surveillance frequencies.

Farley Units 1 and 2 5.5-10 Amendment No.163 (Unit 1)

Amendment No.156 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Diesel Fuel Oil Testinq Program A diesel fuel oil testing program to implement required testing of both new fuel oil and stored fuel oil shall be established. The program shall include sampling and testing requirements, and acceptance criteria, all in accordance with applicable ASTM Standards. The purpose of the program is to establish the following:

a. Acceptability of new fuel oil for use prior to addition to the emergency diesel generator storage tanks by determining that the fuel oil has:

1. an API gravity or an absolute specific gravity within limits,

2. a flash point and kinematic viscosity within limits for ASTM 2D fuel oil, and

3. a clear and bright appearance.

b. Fuel oil stored in the emergency diesel generator storage tanks is within limits by verifying that a sample of diesel fuel oil from the storage tank, obtained in accordance with ASTM-D270-65, is within the acceptable limits specified in Table 1 of ASTM D975-74 when checked for viscosity, water, and sediment every 92 days.

c. The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program surveillance test frequencies.

5.5.14 Technical Specifications (TS) Bases Control Program This program provides a means for processing changes to the Bases of these Technical Specifications.

a. Changes to the Bases of the TS shall be made under appropriate administrative controls and reviews.

b. Licensees may make changes to Bases without prior NRC approval provided the changes do not require either of the following:

1. a change in the TS incorporated in the license; or

2. a change to the updated FSAR or Bases that requires NRC approval pursuant to 10 CFR 50.59.

(continued)

Farley Units 1 and 2 5.5-11 Amendment No. 163 (Unit 1)

Amendment No. 156 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Technical Specifications (TS) Bases Control Program (continued)

c. The Bases Control Program shall contain provisions to ensure that the Bases are maintained consistent with the FSAR.

d. Proposed changes that meet the criteria of Specification 5.5.14b above shall be reviewed and approved by the NRC prior to implementation.

Changes to the Bases implemented without prior NRC approval shall be provided to the NRC on a frequency consistent with 10 CFR 50.71 (e).

5.5.15 Safety Function Determination Program (SFDP)

This program ensures loss of safety function is detected and appropriate actions taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other appropriate actions may be taken as a result of the support system inoperability and corresponding exception to entering supported system Condition and Required Actions. This program implements the requirements of LCO 3.0.6. The SFDP shall contain the following:

a. Provisions for cross train checks to ensure a loss of the capability to perform the safety function assumed in the accident analysis does not go undetected;

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, 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 (continued)

Farley Units 1 and 2 5.5-12 Amendment No.163 (Unit 1)

Amendment No.156 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Safety Function Determination Program (SFDP) (continued)

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.

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 Xl) 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, 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":

Section 9.2.3: The next Type A test, after the March 1994 test for Unit 1 and the March 1995 test for Unit 2, shall be performed within 15 years. This is a one time exception.

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.

(continued)

Farley Units 1 and 2 5.5-13 Amendment No.163 (Unit 1)

Amendment Noi56 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.17 Containment Leakage Rate Testing Program (continued)

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.

Farley Units 1 and 2 5.5-14 Amendment No. 163 (Unit 1),

Amendment No. 156 (Unit 2) l

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Tendon Surveillance Report (continued)

Program shall be reported to the NRC within 30 days. The report shall include a description of the tendon condition, the condition of the concrete (especially at tendon anchorages), the inspection procedures, the tolerances on cracking, and the corrective action taken.

5.6.10 Steam Generator (SG) Tube Inspection Report A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of an inspection performed in accordance with the Specification 5.5.9, Steam Generator (SG) Program. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Nondestructive examination techniques utilized for each degradation mechanism,

d. Location, orientation (if linear), and measured sizes (if available) of service induced indications,

e. Number of tubes plugged during the inspection outage for each active degradation mechanism,

f. Total number and percentage of tubes plugged to date, and

9. The results of condition monitoring, including the results of tube pulls and in-situ testing.

5.6.11 Alternate AC (AAC) Source Out of Service Report The NRC shall be notified if the AAC source is out of service for greater than 10 days.

Farley Units 1 and 2 5.6-6 Amendment No. 163(Unit 1)

Amendment No. 156(Unit 2)

TABLE OF CONTENTS B 3.4.3 RCS Pressure and Temperature (P/T) Limits ............................. B 3.4.3-1 B 3.4.4 RCS Loops-MODES 1 and 2........................................ B 3.4.4-1 B 3.4.5 RCS Loops-MODE 3........................................ B 3.4.5-1 B 3.4.6 RCS Loops-MODE 4 ........................................ B 3.4.6-1 B 3.4.7 RCS Loops-MODE 5, Loops Filled ........................................ B 3.4.7-1 B 3.4.8 RCS Loops-MODE 5, Loops Not Filled ................................... B 3.4.8-1 B 3.4.9 Pressurizer ........................................ B 3.4.9-1 B 3.4.10 Pressurizer Safety Valves ........................................ B 3.4.10-1 B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) ...... B 3.4.11-1 B 3.4.12 Low Temperature Overpressure Protection (LTOP)

System ........................................ B 3.4.12-1 B 3.4.13 RCS Operational LEAKAGE ........................................ B 3.4.13-1 B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage ............................. B 3.4.14-1 B 3.4.15 RCS Leakage Detection Instrumentation .................................... B 3.4.15-1 B 3.4.16 RCS Specific Activity ........................................ B 3.4.16-1 B 3.4.17 Steam Generator (SG) Tube Integrity........................................ B 3.4.17-1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) ......................... B 3.5.1-1 B 3.5.1 Accumulators ........................................ B 3.5.1-1 B 3.5.2 ECCS-Operating ........................................ B 3.5.2-1 B 3.5.3 ECCS-Shutdown ........................................ B 3.5.3-1 B 3.5.4 Refueling Water Storage Tank (RWST) ..................................... B 3.5.4-1 B 3.5.5 Seal Injection Flow ........................................ B 3.5.5-1 B 3.5.6 ECCS Recirculation Fluid pH Control System ............................. B 3.5.6-1 B 3.6 CONTAINMENT SYSTEMS ............ ............................ B 3.6.1-1 B 3.6.1 Containment ........................................ B 3.6.1-1 B 3.6.2 Containment Air Locks ............ ............................ B 3.6.2-1 B 3.6.3 Containment Isolation Valves .................... .................... B 3.6.3-1 B 3.6.4 Containment Pressure ........................................ B 3.6.4-1 B 3.6.5 Containment Air Temperature ....................... ................. B 3.6.5-1 B 3.6.6 Containment Spray and Cooling Systems .................................. B 3.6.6-1 B 3.6.7 Hydrogen Recombiners ........................................ B 3.6.7-1 B 3.6.8 Hydrogen Mixing System (HMS) ........................................ B 3.6.8-1 B 3.6.9 Reactor Cavity Hydrogen Dilution System (RCHDS) ............................... B 3.6.9-1 B 3.7 PLANT SYSTEMS ............................... B 3.7.1-1 B 3.7.1 Main Steam Safety Valves (MSSVs) ............................... B 3.7.1-1 B 3.7.2 Main Steam Isolation Valves (MSIVs) ............................... B 3.7.2-1 B 3.7.3 Main Feedwater Stop Valves and Main Feedwater Regulation Valves (MFRVs) and Associated Bypass Valves .... B 3.7.3-1 Farley Units 1 and 2 ii Revision

TABLE OF CONTENTS B 3.7.4 Atmospheric Relief Valves (ARVs) ......... ................. B 3.7.4-1 B 3.7.5 Auxiliary Feedwater (AFW) System .......................... B 3.7.5-1 B 3.7.6 Condensate Storage Tank (CST) ........ .................. B 3.7.6-1 B 3.7.7 Component Cooling Water (CCW) System ................................ B 3.7.7-1 B 3.7.8 Service Water System (SWS) ............... ..................... B 3.7.8-1 B 3.7.9 Ultimate Heat Sink (UHS) .................................... B 3.7.9-1 B 3.7.10 Control Room Emergency Filtration/Pressurization System (CREFS) ...... B 3.7.10-1 B 3.7.11 Control Room Air Conditioning System (CRACS) ................................... B 3.7.11 -1 B 3.7.12 Penetration Room Filtration (PRF) System ................................. B 3.7.12-1 B 3.7.13 Fuel Storage Pool Water Level ................................... B 3.7.13-1 B 3.7.14 Fuel Storage Pool Boron Concentration ..................................... B 3.7.14-1 B 3.7.15 Spent Fuel Assembly Storage .............. ..................... B 3.7.15-1 B 3.7.16 Secondary Specific Activity ................................... B 3.7.16-1 B 3.8 ELECTRICAL POWER SYSTEMS..................................................... B 3.8.1-1 B 3.8.1 AC Sources-Operating ................................... B 3.8.1 -1 B 3.8.2 AC Sources-Shutdown ................................... B 3.8.2-1 B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air ................................... B 3.8.3-1 B 3.8.4 DC Sources-Operating ................... ,,,,,,,,,,,,,,,,..................... B 3.8.4-1 B 3.8.5 DC Sources-Shutdown ............. B 3.8.5-1 B 3.8.6 Battery Cell Parameters ............................................................. ,B 3.8.6-1 B 3.8.7 Inverters-Operating ......................... ,,,.,,,.,,.B 3.8.7-1 B 3.8.8 Inverters-Shutdown .................... ,,,....,.,.,,,,,,.,,,,,,.B 3.8.8-1 B 3.8.9 Distribution Systems-Operating . B 3.8.9-1 B 3.8.10 Distribution Systems-Shutdown ........................ B 3.8.10-1 B 3.9 REFUELING OPERATIONS ........................ B 3.9.1-1 B 3.9.1 Boron Concentration ........................ B 3.9.1 -1 B 3.9.2 Nuclear Instrumentation ................. B 3.9.2-1 B 3.9.3 Containment Penetrations . , . ......................... B 3.9.3-1 B 3.9.4 Residual Heat Removal (RHR) and Coolant Circulation-High Water Level ..... B 3.9.4-1 B 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation - Low Water Level ......... ................ B 3.9.5-1 B 3.9.6 Refueling Cavity Water Level ......................... B 3.9.6-1 Farley Units 1 and 2 iii Revision I

RCS Loops - MODES 1 and 2 B 3.4.4 BASES APPLICABLE Both transient and steady state analyses have been performed to SAFETY ANALYSES establish the effect of flow on the departure from nucleate boiling (continued) (DNB). The transient and accident-analyses for the plant have been performed assuming three RCS loops are in operation. The majority of the plant safety analyses are based on initial conditions at high core power or zero power. The accident analyses that are most important to RCP operation are the complete loss of forced reactor coolant flow, single RCP locked rotor, partial loss of reactor coolant flow (broken shaft or coastdown), and rod withdrawal events (Ref. 1).

Steady.state DNB analysis has been performed for the three RCS loop operation. For three RCS loop operation, the steady state DNB analysis, which generates the pressure and temperature Safety Limit (SL) (i.e., the departure from nucleate boiling ratio (DNBR) limit) assumes a maximum power level of 120% RTP. This is the design overpower condition for three RCS loop operation. The value for the accident analysis setpoint of the nuclear overpower (high flux) trip is 118% and is based on an analysis assumption that bounds possible instrumentation errors. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.

The plant is designed to operate with all RCS loops in operation to maintain DNBR above the SL, during all normal operations and anticipated transients. By ensuring heat transfer in the nucleate boiling region, adequate heat transfer is provided between the fuel cladding and the reactor coolant.

RCS Loops-MODES 1 and 2 satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The purpose of this LCO is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criteria for DNB, three pumps are required at rated power.

An OPERABLE RCS loop consists of an OPERABLE RCP in operation providing forced flow for heat transport and an OPERABLE SG. I Farley Units 1 and 2 B 3.4.4-2 Revision

RCS Loops - MODE 3 B 3.4.5 BASES LCO The no flow test may be performed in MODE 3, 4, or 5 and requires (continued) that the pumps be stopped for a short period of time. The Note permits the stopping of the pumps in order to perform this test and validate the assumed analysis values. As with the validation of the pump coastdown curve, this test should be performed only once unless the flow characteristics of the RCS are changed. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> time period specified is adequate to perform the desired tests, and operating experience has shown that boron stratification is not a problem during this short period with no forced flow.

Utilization of the Note is permitted provided the following conditions are met, along with any other conditions imposed by initial startup test procedures:

a. No operations are permitted that would dilute the RCS boron concentration, thereby maintaining the margin to criticality. Boron reduction is prohibited because a uniform concentration distribution throughout the RCS cannot be ensured when in natural circulation; and

b. Core outlet temperature is maintained at least 10F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

An OPERABLE RCS loop consists of one OPERABLE RCP and one OPERABLE SG, which has the minimum water level specified in SR 3.4.5.2. This assumes steam removal capability and the availability of a makeup water source (if necessary for extended use of the SG) as required to remove decay heat. An RCP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.

APPLICABILITY In MODE 3, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. The most stringent condition of the LCO, that is, two RCS loops OPERABLE and two RCS loops in operation, applies to MODE 3 with the rod control system capable of rod withdrawal. The least stringent condition, that is, two RCS loops OPERABLE and one RCS loop in operation, applies to MODE 3 with the rod control system not capable of rod withdrawal.

(continued)

Farley Units 1 and 2 B 3.4.5-3 Revision

RCS Loops - MODE 4 B 3.4.6 BASES LCO An OPERABLE RCS loop comprises an OPERABLE RCP and an (continued) OPERABLE SG, which has the minimum water level specified in SR 3.4.6.2. This assumes steam removal capability and the availability of a makeup water source (if necessary for extended use of the SG) as required to remove decay heat.

Similarly for the RHR System, an OPERABLE RHR loop comprises an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger. RCPs and RHR pumps are OPERABLE if they are capable of being powered and are able to provide forced flow if required.

APPLICABILITY In MODE 4, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing. One loop of either RCS or RHR provides sufficient circulation for these purposes. However, two loops consisting of any combination of RCS and RHR loops are required to be OPERABLE to meet single failure considerations.

Operation in other MODES is covered by:

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

LCO 3.4.5, "RCS Loops-MODE 3";

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 and two RHR loops are inoperable, redundancy for heat removal is lost. Action must be initiated to restore a second RCS or RHR loop to OPERABLE status.

The immediate Completion Time reflects the importance of maintaining the availability of two paths for heat removal.

(continued)

Farley Units 1 and 2 B 3.4.6-3 Revision

RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO distribution throughout the RCS cannot be ensured when in (continued) natural circulation; and

b. Core outlet temperature is maintained at least 10F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

Note 2 allows one RHR loop to be inoperable for a period of up to 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />, provided that the other RHR loop is OPERABLE and in operation. This permits periodic surveillance tests to be performed on the inoperable loop during the only time when such testing is safe and possible.

Note 3 requires that the secondary side water temperature of each SG be < 50'F above each of the RCS cold leg temperatures or that the pressurizer water volume is less than 770 cubic feet (24% of wide range, cold, pressurizer level indication) before the start of a reactor coolant pump (RCP) with an RCS cold leg temperature c 3250 F. This restriction is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

Note 4 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting removal of RHR loops from operation when at least one RCS loop is in operation. This Note provides for the transition to MODE 4 where an RCS loop is permitted to be in operation and replaces the RCS circulation function provided by the RHR loops.

Note 5 restricts the number of operating reactor coolant pumps at RCS temperatures less than 1100F. Only one reactor coolant pump is allowed to be in operation below 11 00F (except during pump swap operations) consistent with the assumptions of the P/T Limits Curve.

RHR pumps are OPERABLE if they are capable of being powered and are able to provide flow if required. A SG can perform as a heat sink via natural circulation when it has an adequate water level and is OPERABLE.

Farley Units 1 and 2 B 3.4.7-3 Revision

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses do not SAFETY ANALYSES address operational LEAKAGE. However, other operational LEAKAGE is typically seen as a precursor to a LOCA; the amount of leakage can affect the probability of such an event. The safety analysis for an event resulting in steam discharge to the atmosphere assumes that primary to secondary LEAKAGE from all steam generators (SGs) is 1 gpm as a result of accident induced conditions. The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gpd (i.e. total leakage less than or equal to 450 gpd) is significantly less than the conditions assumed in the safety analysis (with leakage assumed to occur at room temperature in both cases).

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident.

To a lesser extent, other accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid.

The FSAR (Ref. 3) analysis for SGTR assumes the contaminated secondary fluid is released via the main steam safety valves. The majority of the activity released to the atmosphere results from the tube rupture. Therefore, the I gpm primary to secondary LEAKAGE safety analysis assumption is relatively inconsequential.

The SLB is more limiting for primary to secondary LEAKAGE. The safety analysis for the SLB assumes 500 gpd and 470 gpd primary to secondary LEAKAGE in the faulted and intact steam generators respectively as an initial condition. The dose consequences resulting from the SLB accident are bounded by a small fraction (i.e., 10%) of the limits defined in 10 CFR 100. The RCS specific activity assumed was 0.5 pCi/gm DOSE EQUIVALENT 1-131 at a conservatively high letdown flow of 145 gpm, with either a pre-existing or an accident initiated iodine spike. These values bound the Technical Specifications values.

The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

Farley Units 1 and 2 B 3.4.13-2 Revision

RCS Operational LEAKAGE B 3.4.13 BASES LCO RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

b. Unidentified LEAKAGE One gallon per minute (gpm) of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the containment air monitoring and containment sump level monitoring equipment can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE to the containment from specifically known and located sources, but does not include pressure boundary LEAKAGE or controlled reactor coolant pump (RCP) seal leakoff (a normal function not considered LEAKAGE). Violation of this LCO could result in continued degradation of a component or system.

d. Primary to SecondarV LEAKAGE Through Any One SG The limit of 150 gpd per each SG is based on the operational LEAKAGE performance criterion in NEI 97-06, Steam Generator Program Guidelines (Ref. 4). The Steam Generator Program operational LEAKAGE performance criterion in NEI 97-06 states, "The RCS operational primary to secondary leakage through any one SG shall be limited to 150 gallons per day." The limit is based on operating experience with SG tube degradation mechanisms that result in tube leakage. The operational leakage rate criterion in conjunction with the implementation of the Steam Generator Program is an effective measure for minimizing the frequency of steam generator tube ruptures.

Farley Units 1 and 2 B 3.4.13-3 Revision

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest when the RCS is pressurized.

In MODES 5 and 6, LEAKAGE limits are not required because the reactor coolant pressure is far lower, resulting in lower stresses and reduced potentials for LEAKAGE.

LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leak tight.

If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable identified LEAKAGE.

ACTIONS A.1 Unidentified LEAKAGE or identified LEAKAGE in excess of the LCO limits must be reduced to within limits within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />. This Completion Time allows time to verify leakage rates and either identify unidentified LEAKAGE or reduce LEAKAGE to within limits before the reactor must be shut down. This action is necessary to prevent further deterioration of the RCPB.

B.1 and B.2 If any pressure boundary LEAKAGE exists, or primary to secondary LEAKAGE is not within limit, or if unidentified or identified LEAKAGE cannot be reduced to within limits within 4 hours0.167 days <br />0.0238 weeks <br />0.00548 months <br />, the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. The reactor must be brought to MODE 3 within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and MODE 5 within 36 hours1.5 days <br />0.214 weeks <br />0.0493 months <br />. This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

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 MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

Farley Units 1 and 2 B 3.4.13-4 Revision

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance.

The RCS water inventory balance must be met with the reactor at steady state operating conditions and near operating pressure. The Surveillance is modified by two Notes. Note 1 states that this SR is not required to be performed in MODES 3 and 4 until 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> of steady state operation near operating pressure have been established.

Steady state operation is required to perform a proper inventory balance; calculations during maneuvering are not useful and a Note requires the Surveillance to be met when steady state is established.

For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment air cooler condensate flow rate. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These leakage detection systems are specified in LCO 3.4.15, "RCS Leakage Detection Instrumentation."

Note 2 states that this SR is not applicable to primary to secondary LEAKAGE. This is because LEAKAGE of 150 gpd cannot be measured accurately by an RCS water inventory balance.

The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. A Note under the Frequency column states that this SR is required to be performed during steady state operation.

(continued)

Farley Units 1 and 2 B 3.4.13-5 Revision

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.2 REQUIREMENTS (continued) This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gpd through any one SG. Satisfying the primary to secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.17, "Steam Generator Tube Integrity," should be evaluated. The 150 gpd limit is measured at room temperature as described in Reference 5. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.

The Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency of 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. During normal operation the primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with EPRI guidelines.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 30.

2. Regulatory Guide 1.45, May 1973.

3. FSAR, Section 3.1.2.6, 5.2.7, 10.4, 11.0,12.0 and 15.0.

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

5. EPRI TR-104788, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

Farley Units 1 and 2 B 3.4.13-6 Revision

SG Tube Integrity B 3.4.17 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.17 Steam Generator (SG) Tube Integrity BASES BACKGROUND Steam generator (SG) tubes are small diameter, thin walled tubes that carry primary coolant through the primary to secondary heat exchangers. The SG tubes have a number of important safety functions. SG tubes are an integral part of the reactor coolant pressure boundary (RCPB) and, as such, are relied on to maintain the primary system's pressure and inventory. The SG tubes isolate the radioactive fission products in the primary coolant from the secondary system. In addition, as part of the RCPB, the SG tubes are unique in that they act as the heat transfer surface between the primary and secondary systems to remove heat from the primary system. This Specification addresses only the RCPB integrity function of the SG.

The SG heat removal function is addressed by LCO 3.4.4, "RCS Loops - MODES 1 and 2," LCO 3.4.5, "RCS Loops - MODE 3,"

LCO 3.4.6, "RCS Loops - MODE 4," and LCO 3.4.7, "RCS Loops -

MODE 5, Loops Filled."

SG tube integrity means that the tubes are capable of performing their intended RCPB safety function consistent with the licensing basis, including applicable regulatory requirements.

SG tubing is subject to a variety of degradation mechanisms. SG tubes may experience tube degradation related to corrosion phenomena, such as wastage, pitting, intergranular attack, and stress corrosion cracking, along with other mechanically induced phenomena such as denting and wear. These degradation mechanisms can impair tube integrity if they are not managed effectively. The SG performance criteria are used to manage SG tube degradation.

Specification 5.5.9, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met. There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Specification 5.5.9. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

(continued)

Farley Units 1 and 2 B 3.4.17-1 Revision

SG Tube Integrity B 3.4.17 BASES BACKGROUND The processes used to meet the SG performance criteria are defined (continued) by the Steam Generator Program Guidelines (Ref. 1).

APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting SAFETY ANALYSES design basis event for SG tubes and avoiding an SGTR is the basis for this Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes the contaminated secondary fluid is released via the main steam safety valves. The majority of the activity released to the atmosphere results from the tube rupture.

The analysis for design basis accidents and transients other than a SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture). In these analyses, the steam discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gpm as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16, "RCS Specific Activity,"

limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the repair criteria be plugged in accordance with the Steam Generator Program.

During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. If a tube was determined to satisfy the repair criteria but was not plugged, the tube may still have tube integrity.

(continued)

Farley Units 1 and 2 B 3.4.17-2 Revision

SG Tube Integrity B 3.4.17 BASES LCO In the context of this Specification, a SG tube is defined as the entire (continued) length of the tube, including the tube wall between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

A SG tube has tube integrity when it satisfies the SG performance criteria. The SG performance criteria are defined in Specification 5.5.9, "Steam Generator Program," and describe acceptable SG tube performance. The Steam Generator Program also provides the evaluation process for determining conformance with the SG performance criteria.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. Failure to meet any one of these criteria is considered failure to meet the LCO.

The structural integrity performance criterion provides a margin of safety against tube burst or collapse under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification. Tube burst is defined as, "The gross structural failure of the tube wall. The condition typically corresponds to an unstable opening displacement (e.g., opening area increased in response to constant pressure) accompanied by ductile (plastic) tearing of the tube material at the ends of the degradation." Tube collapse is defined as, "For the load displacement curve for a given structure, collapse occurs at the top of the load versus displacement curve where the slope of the curve becomes zero." Structural integrity requires that the primary membrane stress intensity in a tube not exceed the yield strength for all ASME Code,Section III, Service Level A (normal operating conditions) and Service Level B (upset or abnormal conditions) transients included in the design specification. This includes safety factors and applicable design basis loads based on ASME Code, Section 1II,Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 1 gallon per minute (gpm) total from all SGs. The accident (continued)

Farley Units 1 and 2 B 3.4.17-3 Revision

SG Tube Integrity B 3.4.17 BASES LCO induced leakage rate includes any primary to secondary (continued) LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

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

The limit on operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gpd. This limit is based on the assumption that a single crack leaking this amount would not propagate to a SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by SR 3.4.17.2. An evaluation of SG tube integrity of the (continued)

Farley Units 1 and 2 B 3.4.17-4 Revision

SG Tube Integrity B 3.4.17 BASES ACTIONS A.1 and A.2 (continued) affected tube(s) must be made. Steam generator tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

A Completion Time of 7 days is sufficient to complete the evaluation while minimizing the risk of plant operation with a SG tube that may not have tube integrity.

If the evaluation determines that the affected tube(s) have tube integrity, Required Action A.2 allows plant operation to continue until the next refueling outage or SG inspection provided the inspection interval continues to be supported by an operational assessment that reflects the affected tubes. However, the affected tube(s) must be plugged prior to entering MODE 4 following the next refueling outage or SG inspection. This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> and MODE 5 within 36 hours1.5 days <br />0.214 weeks <br />0.0493 months <br />.

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

Farley Units 1 and 2 B 3.4.17-5 Revision

SG Tube Integrity B 3.4.17 BASES SURVEILLANCE SR 3.4.17.1 REQUI REMENTS During shutdown periods the SGs are inspected as required by this SR and the Steam Generator Program. NEI 97-06, Steam Generator Program Guidelines (Ref. 1), and its referenced EPRI Guidelines, establish the content of the Steam Generator Program.

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

During SG inspections a condition monitoring assessment of the SG tubes is performed. The condition monitoring assessment determines the "as found" condition of the SG tubes. The purpose of the condition monitoring assessment is to ensure that the SG performance criteria have been met for the previous operating period.

The Steam Generator Program determines the scope of the inspection and the methods used to determine whether the tubes contain flaws satisfying the tube repair criteria. Inspection scope (i.e., which tubes or areas of tubing within the SG are to be inspected) is a function of existing and potential degradation locations. The Steam Generator Program also specifies the inspection methods to be used to find potential degradation.

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

The Steam Generator Program defines the Frequency of SR 3.4.17.1. The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection.

In addition, Specification 5.5.9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.17.2 During an SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 5.5.9 (continued)

Farley Units 1 and 2 B 3.4.17-6 Revision

SG Tube Integrity B 3.4.17 BASES SURVEILLANCE SR 3.4.17.2 (continued)

REQUIREMENTS are intended to ensure that tubes accepted for continued service satisfy the SG performance criteria with allowance for error in the flaw size measurement and for future flaw growth. In addition, the tube repair criteria, in conjunction with other elements of the Steam Generator Program, ensure that the SG performance criteria will continue to be met until the next inspection of the subject tube(s).

Reference 1 and Reference 6 provide guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

The Frequency of "Prior to entering MODE 4 following a SG inspection" ensures that the Surveillance has been completed and all tubes meeting the repair criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.

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

2. 10 CFR 50 Appendix A, GDC 19.

3. 10CFR100.

4. ASME Boiler and Pressure Vessel Code, Section 1I1, Subsection NB.

5. Draft Regulatory Guide 1.1 21, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

6. EPRI TR-107569, "Pressurized Water Reactor Steam Generator Examination Guidelines."

Farley Units 1 and 2 B 3.4.1 7-7 Revision