ML062410021

Tech Spec Pages for Amendments 144 and 124 Regarding Steam Generator Tube Integrity

ML062410021
Person / Time
Site:	Vogtle
Issue date:	08/28/2006
From:	NRC/NRR/ADRO/DORL/LPLII-1
To:
Gratton C, NRR/DORL, 415-1055
Shared Package
ML062360577	List: ML062410021
References
TAC MD1075, TAC MD1076
Download: ML062410021 (24)

Text

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 144 and the Environmental Protection Plan contained in Appendix B, both of which are attached hereto, are hereby incorporated into this license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) Southern Nuclear Operating Company shall be capable of establishing containment hydrogen monitoring within 90 minutes of initiating safety injection following a loss of coolant accident.

(4) DELETED (5) DELETED (6) DELETED (7) DELETED (8) DELETED (9) DELETED (10) Additional Conditions The Additional Conditions contained in Appendix D, as revised through Amendment No. 102, are hereby incorporated into this license. Southern Nuclear shall operate the facility in accordance with the Additional Conditions.

D. The facility requires exemptions from certain requirements of 10 CFR Part 50 and 10 CFR Part 70. These include (a) an exemption from the requirements of 10 CFR 70.24 for two criticality monitors around the fuel storage area, and (b) an exemption from the requirements of Paragraph III.D.2(b)(ii) of Appendix J of 10 CFR 50, the testing of containment air locks at times when containment integrity is not required.

The special circumstances regarding exemption b are identified in Section 6.2.6 of SSER5.

An exemption was previously granted pursuarft to 10 CFR 70.24. The exemption was granted with NRC materials license No. SNM-1967, issued August 21, 1986, and relieved GPC from the requirement of having a criticality alarm system. GPC and Southern Nuclear are hereby exempted from the criticality alarm system provision of 10 CFR 70.24 so far as this section applies to the storage of fuel assemblies held under this license.

These exemptions are authorized by law, will not present an undue risk to the public health and safety, and are consistent with the common defense and security. The exemptions in items b and c above are granted pursuant to 10 CFR 50.12. With Amendment No. 144 (Unit 1)

C. This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter in effect, and is subject to the additional conditions specified or incorporated below.

(1) Maximum Power Level Southern Nuclear is authorized to operate the facility at reactor core power levels not in excess of 3565 megawatts thermal (100 percent power) in accordance with the conditions specified herein.

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 124, and the Environmental Protection Plan contained in Appendix B, both ot which are attached hereto, are hereby incorporated into this license. Southern Nuclear shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

The Surveillance Requirements (SRs) contained in the Appendix A Technical Specifications and listed below are not required to be performed immediately upon implementation of Amendment No. 74. The SRs listed below shall be successfully demonstrated prior to the time and condition specified below for each:

a) DELETED b) DELETED c) SR 3.8.1.20 shall be successfully demonstrated at the first regularly scheduled performance after implementation of this license amendment.

(3) Southern Nuclear Operating Company shall be capable of establishing containment hydrogen monitoring within 90 minutes of initiating safety injection following a loss of coolant accident.

(4) Additional Conditions The Additional Conditions contained in Appendix D, as revised through Amendment No. 80, are hereby incorporated into this license. Southern Nuclear shall operate the facility in accordance with the Additional Conditions.

D. The facility requires exemptions from certain requirements of 10 CFR Part 50 and 10 CFR Part 70. These include (a) an exemption from the requirements of 10 CFR 70.24 for two criticality monitors around the fuel storage area, and (b) an exemption from the requirements of Paragraph III.D.2(b)(ii) of Appendix J of 10 CFR 50, the testing of containment air locks at times when containment integrity is not required.

The special circumstances regarding exemption b are identified in Section 6.2.6 of SSER 8.

Amendment No. I124(Unit 2)

TABLE OF CONTENTS 3.3 INSTRUMENTATION ........................................................................... 3.3.1-1 3.3.1 Reactor Trip System (RTS) Instrumentation .......................................... 3.3.1-1 3.3.2 Engineered Safety Feature Actuation System (ESFAS)

Instrum entation ............................................................................. 3.3.2-1 3.3.3 Post Accident Monitoring (PAM) Instrumentation .................................. 3.3.3-1 3.3.4 Remote Shutdown System .................................................................... 3.3.4-1 3.3.5 4.16 kV ESF Bus Loss of Power(LOP) Instrumentation ........................ 3.3.5-1 3.3.6 Containment Ventilation Isolation Instrumentation ................................ 3.3.6-1 3.3.7 Control Room Emergency Filtration System (CREFS)

Actuation Instrumentation .............................................................. 3.3.7-1 3.3.8 High Flux at Shutdown Alarm (HFASA) ................................................. 3.3.8-1 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 Cold Overpressure Protection Systems (COPS) ................................... 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 I 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 Recirculation Fluid pH Control System .................................................. 3.5.6-1 (continued)

Vogtle Units I and 2 H Amendment No144(Unit 1)

Amendment No124(Unit 2)

TABLE OF CONTENTS (continued)

LIST OF TABLES 1.1-1 MO D E S ................................................................................................ 1.1-7 3.3.1-1 Reactor Trip System Instrumentation .................................................... 3.3.1-14 3.3.2-1 Engineered Safety Feature Actuation System Instrumentation ......................................... 3.3.2-9 3.3.3-1 Post Accident Monitoring Instrumentation ............................................. 3.3.3-6 3.3.4-1 Remote Shutdown System Instrumentation and Controls ..................... 3.3.4-3 3.3.6-1 Containment Ventilation Isolation Instrumentation .................... 3.3.6-5 3.3.7-1 CREFS Actuation Instrumentation ......................................................... 3.3.7-6 3.7.1-1 Maximum Allowable Power Range Neutron Flux High Trip Setpoint with Inoperable Main Steam Safety Valves ...................... 3.7.1-3 3.7.1-2 Main Steam Safety Valve Lift Settings .................................................. 3.7.1-4 I

(continued)

VogUe Units I and 2 v Amendment No144 (Unit 1)

Amendment No.] 2 4 (Unit 2)

Definitions 1.1 1.1 Definitions (continued)

E_-AVERAGE shall be the average (weighted in proportion to DISINTEGRATION ENERGY the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines, with half lives > 14 minutes, making up at least 95% of the total noniodine activity in the coolant.

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time FEATURE (ESF) RESPONSE interval from when the monitored parameter exceeds its TIME ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e.,

the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. 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.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water injection or leakoff), that is captured and conducted to collection systems or a sump or collecting tank;

2. LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or

3. Reactor Coolant System (RCS) LEAKAGE through a steam generator to the Secondary System (primary to secondary LEAKAGE); I (continued)

Vogtle Units 1 and 2 1.1-3 Amendment No.144 (Unit 1)

Amendment No.124 (Unit 2)

Definitions 1.1 1.1 Definitions LEAKAGE b. Unidentified LEAKAGE (continued)

All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE;

c. Pressure Boundary LEAKAGE LEAKAGE (except primary to secondary LEAKAGE) I through a nonisolable fault in an RCS component body, pipe wall, or vessel wall.

MASTER RELAY TEST A MASTER RELAY TEST shall consist of energizing each master relay and verifying the OPERABILITY of each relay.

The MASTER RELAY TEST shall include a continuity check of each associated slave relay.

MODE A MODE shall correspond to any one inclusive combination of core reactivity condition, power level, average reactor coolant temperature, and reactor vessel head closure bolt tensioning specified in Table 1.1-1 with fuel in the reactor vessel.

OPERABLE- OPERABILITY A system, subsystem, train, component, or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified safety function(s) and when all necessary attendant instrumentation, controls, normal or emergency electrical power, cooling and seal water, lubrication, and other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its specified safety function(s) are also capable of performing their related support function(s).

PHYSICS TESTS PHYSICS TESTS shall be those tests performed to measure the fundamental nuclear characteristics of the reactor core and related instrumentation. These tests are:

(continued)

Vogtle Units 1 and 2 1.1-4 Amendment No14 4 (Unit 1)

Amendment No124 (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. I gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and I

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 within limits.

limits 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.

vogtle Units 1 and 2 3.4.13-1 Amendment No.1 4 4 (Unit 1)

Amendment No.124 (Unit 2)

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

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

2. Only required to be performed during steady state operation.

3. Not applicable to primary to secondary LEAKAGE.

Perform RCS water inventory balance. Once within 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> after achieving steady state operation AND 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> thereafter 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.

Vogtle Units I and 2 3.4.13-2 Amendment No.144 (Unit 1)

Amendment No.124 (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 NOTI r-Separate Condition entry is allowed for each SG tL 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 maintained criteria and not plugged until the next refueling outage in accordance with the or SG tube inspection.

Steam Generator Program. AND A.2 Plug the affected tube(s) in Prior to entering accordance with the Steam MODE 4 following the Generator Program. next refueling 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.

Vogtle Units I and 2 3.4.17-1 Amendment No144 (Unit 1)

Amendment No. 1 2 4 (Unit 2)

SG Tube Integrity 3.4.17 SURVEILLANCE REQUIREMENTS SURVEILLANCE 1__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 Prior to entering the tube repair criteria is plugged in accordance MODE 4 following a with the Steam Generator Program. SG tube inspection Vogtle Units 1 and 2 3.4.17-2 Amendment No.144 (Unit 1)

Amendment No.1 2 4 (Unit 2)

Programs and Manuals 5.5

.5.5 Programs and Manuals 5.5.8 Inservice Testina Proaram 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 Required Frequencies for Addenda terminology for performing inservice inservice testing 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 At least once per 184 days 6 months 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.

(continued)

Vogtle Units 1 and 2 5.5-6 Amendment No. 144 (Unit 1)

Amendment No. 24 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 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 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 in-service steam generator tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cool down and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 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.

(continued)

Vogtle Units 1 and 2 5.5-7 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

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

2. Accident induced leakage performance criterion: The primary to secondary accident induced leakage rate for any design basis accident, other than a SG lube 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. Leakage is not to exceed 1 gpm per SG.

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

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.

The following alternate tube repair criteria may be applied as an alternative to the 40% depth based criteria:

1. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation found in the portion of the tube below 17 inches from the top of the hot leg tubesheet does not require plugging.

For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, degradation identified in the portion of the tube from the top of the hot leg tubesheet to 17 inches below the top of the tubesheet shall be plugged upon detection.

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. For Unit 2 during Refueling Outage 11 and the subsequent operating cycle, the portion of the tube below 17 inches from the top of the hot leg tubesheet is excluded. 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 (continued)

Vogtle Units 1 and 2 5.5-8 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

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

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 120, 90, 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 48 effective full power months or two refueling outages (whichever is less) without being inspected.

3. Ifcrack 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 nondestructive 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.

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;

d. Procedures for the recording and management of data;

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

.. Chditionis; and poin..c.m.str (continued)

Vogtle Units 1 and 2 5.5-9 Amendment No. 144 (Unit 1)

Amendment No. 1 2 4 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Secondary Water Chemistry Program (continued)

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 Pro-gram (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 accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1980:

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 : 0.05% when tested in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1980 at the system flow rate specified below

+/- 10%.

ESF Ventilation System Flow Rate Control Room Emergency Filtration System (CREFS) 19,000 CFM Piping Penetration Area Filtration and Exhaust (PPAFES) 15,500 CFM

b. Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows a penetration and system bypass < 0.05% when tested in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1980 at the system flow rate specified below +/- 10%.

ESF Ventilation System Flow Rate CREFS 19,000 CFM PPAFES 15,500 CFM

c. Demonstrate for each of the ESF systems that a laboratory test of a sample of the charcoal adsorber, when obtained as described in Regulatory Guide 1.52, Revision 2, shows the methyl iodide penetration less than or equal to the value specified below-when tested in accordance with ASTM D3803-1989 at a temperature of 30 00 and greater than or equal to the relative humidity specified below.

(continued)

Vogtle Units 1 and 2 5.5-10 Amendment No.144 (Unit 1)

Amendment No.124 (Unit 2) I

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

ESF Ventilation System Penetration RH CREFS .2% 70%

PPAFES 10% 95%

d. Demonstrate for each of the ESF systems that the pressure drop across the combined HEPA filters, the charcoal adsorbers, and CREFS cooling coils is less than the value specified below when tested in accordance with Regulatory Guide 1.52, Revision 2, and ASME N510-1989 at the system flow rate specified below +/- 10%.

ESF Ventilation System Delta P Flow Rate CREFS 7.1 in. 19,000 CFM water gauge PPAFES 6 in. 15,500 CFM water gauge

e. Demonstrate that the heaters for the CREFS dissipate > 95 kW when corrected to 460 V when tested in accordance with ASME N510-1989.

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 Storaae Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the Gaseous Waste Processing System, the quantity of radioactivity contained in each Gas Decay Tank, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. The gaseous radioactivity quantities shall be determined following the methodology in Branch Technical Position (BTP) ETSB 11-5, 'Postulated Radioactive Release due to Waste Gas System Leak or Failure." The liquid radwaste quantities shall be limited to 10 curies per outdoor tank In accordance with Standard Review Plan, Section 15.7.3, "Postulated Radioactive Release due to Tank Failures."

t"lhe program shall include:

(continued)

Vogtle Units I and 2 5.5-11 Amendment No. 144 (Unit 1)

Amendment No.124 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Explosive Gas and Storage Tank Radioactivity Monitorinq Program (continued)

a. The limits for concentrations of hydrogen and oxygen in the Gaseous Waste Processing System and a surveillance program to ensure the limits are maintained. Such limits shall be appropriate to the system's design criteria (i.e., whether or not the system is designed to withstand a hydrogen explosion);

b. A surveillance program to ensure that the quantity of radioactivity contained in each gas decay 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 limited to < 10 curies per tank, excluding tritium and dissolved or entrained noble gases. This surveillance program provides assurance that in the event of an uncontrolled release of the tank's contents, the resulting concentrations would be less than the limits of 10 CFR 20, Appendix B, Table 2, Column 2, at the nearest potable water supply and the nearest surface water supply in an unrestricted area.

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.

5.5.13 Diesel Fuel Oil Testing 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 storage tanks by determining that the fuel oil has:

1. an API gravity or an absolute specific gravity within limits, or an API gravity or specific gravity within limits when compared to the supplier's certificate;

2. a.flash point within limits for ASTM 2D fuel oil, and, if gravity was not determined by comparison with supplier's certification, a kinematic viscosity within limits for ASTM 2D fuel oil; and (continued)

Vogtle Units 1 and 2 5.5-12 Amendment No.144 (Unit 1)

Amendment No.12 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Diesel Fuel Oil Testing Program (continued)

3. a clear and bright appearance with proper color.

b. Other properties for ASTM 2D fuel oil are within limits within 30 days following sampling and addition to storage tanks; and

c. Total particulate concentration of the fuel oil is < 10 mg/I when tested every 31 days.

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

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 (b) 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. Additionalli,-otheir appirpriate-actiond rfiad-y betak6n as a result of the support system inoperability and corresponding exception to (continued)

Vogtle Units 1 and 2 5.5-13 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

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

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 MS and FW Pinina Inspection Program This program shall provide for the inspection of the four Main Steam and Feedwater lines from the containment penetration flued head outboard welds, up to the first five-Way restraint. The extent of the in'service examinations coftoleted during each inspection interval (ASME Code Section XI) shall provide 100%

(continued)

Vogtle Units 1 and 2 5.5-14 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.16 MS and FW Piping Inspection Program (continued) volumetric examination of circumferential and longitudinal welds to the extent practical. This augmented inservice inspection is consistent with the requirements of NRC Branch Technical Position MEB 3-1, "Postulated Break and Leakage Locations in Fluid System Piping Outside Containment," November 1975 and Section 6.6 of the FSAR.

5.5.17 Containment Leakage Rate Testing Program A program shall be established to implement the leakage rate testing of the 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-Testing Program," dated September 1995, as modified by the following exceptions:

1. Leakage rate testing for containment purge valves with resilient seals is performed once per 18 months in accordance with LCO 3.6.3, SR 3.6.3.6 and SR 3.0.2.

2. Containment personnel air lock door seals will be tested prior to reestablishing containment integrity when the air lock has been used for containment entry. When containment integrity is required and the air lock has been used for containment entry, door seals will be tested at least once per 30 days during the period that containment entry(ies) is (are) being made.

3. 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 ASME Section XI Code, Subsection IWL, except where relief has been authorized by the NRC. At the discretion of the licensee, 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/refueling outage.

4. A one time exception to NEI 94-01, Rev. 0, "Industry Guidelines for Implementing Performance-Based Option of 10 CFR 50, Appendix JX:

Section 9.2.3: - the next Type A test, after the March 2002 test (continued)

Vogtle Units 1 and 2 5.5-15 Amendment No. 144 (Unit 1)

Amendment No. 1 2 4 (Unit 2)

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.17 Containment Leakage Rate Testing Program (continued) for Unit I and the March 1995 test for Unit 2, shall be performed within 15 years.

The peak calculated primary containment internal pressure for the design basis loss of coolant accident, Pa, is 37 psig.

The maximum allowable containment leakage rate, L,, at Pa, is 0.2% of primary containment air weight per day.

Leakage rate acceptance criteria are:

a. Containment overall leakage rate acceptance criteria are _ 1.0 La. During the first unit startup following testing in accordance with this program, the leakage rate acceptance criteria are _ 0.60 La for the combined Type B and Type 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 L, when tested at -eP,,

2) For each door, the leakage rate is _ 0.01 La when pressurized to

ŽPa.

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 Configuration Risk Management Program The Configuration Risk Management Program (CRMP) provides a proceduralized risk-informed assessment to manage the risk associated with equipment inoperability. The program applies to technical specification structures, systems, or components for which a risk-informed allowed outage time has been granted. The program shall include the following elements:

a. Provisions for the control and implementation of a Level 1 at power internal events PRA-informed methodology. The assessment shall be capable of evaluating the applicable plant configuration.

(continued)

Vogtle Units 1 and 2 5.5-16 Amendment No.144 (Unit 1)

Amendment No. 1 2 4 (Unit 2)

Programs and Manuals

'5.5 5.5 Programs and Manuals 5.5.18 Configuration Risk Management Program (continued)

b. Provisions for performing an assessment prior to entering the LCO Condition for preplanned activities.

c. Provisions for performing an assessment after entering the LCO Condition for unplanned entry into the LCO Condition.

d. Provisions for assessing the need for additional actions after the discovery of additional equipment out of service conditions while in the LCO Condition.

e. Provisions for considering other applicable risk significant contributors such as Level 2 issues and external events, qualitatively or quantitatively.

5.5.19 Battery Monitoring and Maintenance Program This program provides for restoration and maintenance, based on the recommendations of IEEE Standard 450-1995, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Vented Lead-Acid Batteries for Stationary Applications," of the following:

a. Actions to restore battery cells with float voltage < 2.13 V, and b Actions to equalize and test battery cells that had been discovered with electrolyte level below the top of the plates.

Vogtle Units I and 2 5.5-17 Amendment No.144 (Unit 1) I Amendment No.124 (Unit 2) I

Programs and Manuals 5.5 Sample Size Criteria 4%

2%

01 3 15 25 35 II I 1 I Time After Initial Structural Integrity Testing of Containment, Years (Lift-Off Testing Schedule, Containment No. 1) 0 35 15 25 35 I II 1 i Time After Initial Structural Integrity Testing of Containment, Years (Lift-Off Testing Schedule, Containment No. 2)

Schedule to be used Drovided:

a. The containments are identical in all aspects such as size, tendon system, design, materials of construction, and method of construction. The tendon system for Unit 2 does not provide for detensioning' Detensioning can be performed only on the Unit 1 tendon system.

b. The 1-year inspection for Unit 2 will consist of a visual inspection only. No lift-off testing will be performed on Unit 2 until the 3-year inspection.

c. There is no unique situation that may subject either containment to a different potential for structural or tendon deterioration.

d. The Unit 1 and Unit 2 surveillances may be performed back-to-back to facilitate detensioning of Unit 1 tendons during the Unit 2 surveillance.

Figure 5.5.6-1 Schedule of Lift-Off Testing for Two Containments at a Site Vogtle Units 1 and 2 5.5-18 Amendment No. 144 (Unit 1)

Amendment No. 124 (Unit 2)

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.9 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Prestressed Concrete Containment Tendon Surveillance 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 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,

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

Vogtle Units 1 and 2 5.6-6 Amendment No.144 (Unit 1)

Amendment No.12 4 (Unit 2)