ML063000028

Tech Spec Pages for Amendments 248 and 228 Regarding Consolidated Line Item Improvement Process for the Steam Generator Tube Integrity

ML063000028
Person / Time
Site:	North Anna
Issue date:	10/16/2006
From:	NRC/NRR/ADRO/DORL/LPLII-1
To:
References
TAC MD1838, TAC MD1839
Download: ML063000028 (42)

Text

(2) Pursuant to the Act and 10 CFR Part 70, VEPCO to receive, possess, and use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Updated Final Safety Analysis Report; (3) Pursuant to the Act and 10 CFR Parts 30,40, and 70, VEPCO to receive, possess, and use at any time any byproduct, source, and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (4) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, VEPCO to receive, possess, and use in amounts as required any byproduct, source, or special nuclear material, without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or component; and (5) Pursuant to the Act and 10 CFR Parts 30 and 70, VEPCO to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This renewed operating license shall be deemed to contain and is subject to the conditions specified in the following Commission regulations in 10 CFR Chapter I: Part 20, Section 30.34 of Part 30, Section 40.41 of Part 40, Sections 50.54 and 50.59 of Part 50, and Section 70.32 of Part 70; 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 VEPCO is authorized to operate the North Anna Power Station, Unit No. 1, at reactor core power levels not in excess of 2893 megawatts (thermal).

(2) Technical Specifications The Technical Sperifications contained InAppendix A, as revised through Amendment No. 248 are hereby Incorporated In the renewed license.

The licensee shall operate the facility Inaccordance with the Technical Specifications..

Renewed Ucense No. NPF-4 Amendment No. 24 8

(3) Pursuant to the Act and 10 CFR Parts 30,40, and 70, VEPCO to receive, possess, and use at any time any byproduct, source, and special nuclear material as sealed neutron sources for reactor sartup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors In amounts as required; .

(4) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, VEPCO to receive, possess, and use in amounts as required any byproduct, source, or special nuclear material, without restriction to cenilcal orphysical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (5) Pursuant to the Act and 10 CFR Parts 30, 40, and 70, VEPCO to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the fact=y.

C. This renewed license shall be deemed to contain and is sabject to the conditions specified in the Commission's regulations as set forth in 10 CFR Chapter Iand is subject to all applicable provisions of the Act and to the dises, 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 VEPCO is authorized to operate the facility at stwady state reactor core power levels not in excess of 2893 megawatts (hvwmal).

(2) Technical Specifications The Technical Specifications contained in Appendc A. as revised through Amendment No. 228 are hereby Incorporated in the renewed license.

The licensee shall operate the facility in accordarc.e ith the Technical Specifications.

(3) Additional Conditions The matters specified in the following conditions shall be completed to the satisfaction of the Commission within the stated time periods following the issuance of the condition or within the operational restrictions indicated. The removal of thes6 condMons shall be made by an amendment to the renewed license supported by a favorable evaluation by the Commission:

a. If VEPCO plans to remove or to make sipf'lcant changes inthe normal operation of equipment that conbotis the amount of radioactivity in effluents from the North Anna Power Station, the Red License No. NPF-7

... ' .--Aadjuert N.O.- 2 2 8

TECHNICAL SPECIFICATIONS TABLE OF CONTENTS 3.4 REACTOR COOLANT SYSTEM (RCS) (continued) 3.4.10 Pressurizer Safety Valves ..... ............ .3.4.10-1 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) .................. . .... .3.4.11-1 3.4.12 Low Temperature Overpressure Protection (LTOP)

System ... .3.4.12-1 3.4.13 RCS Operational LEAKAGE. ............. .3.4.13-1 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage . . . .3.4.14-1 3.4.15 RCS Leakage Detection Instrumentation ........ .3.4.15-1 3.4.16 RCS Specific Activity ..... .............. .3.4.16-1 3.4.17 RCS Loop Isolation Valves ..... ............ .3.4.17-1 3.4.18 RCS Isolated Loop Startup . ........... .3.4.18-1 3.4.19 RCS Loops-Test Exceptions. ............ .3.4.19-1 3.4.20 Steam Generator (SG) Tube Integrity .......... .3.4.20-1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) . 3.5.1-1 3.5.1 Accumulators . . . . . . . . . . . 3.5.1-1 3.5.2 ECCS-Operating .......... 3.5.2-1 3.5.3 ECCS-Shutdown ............. 3.5.3-1 3.5.4 Refueling Water Storage Tank (RWST) 3.5.4-1 3.5.5 Seal Injection Flow ........... 3.5.5-1 3.5.6 Boron Injection Tank (BIT) ....

• 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 Quench Spray (QS) System .....

• 3.6.6-1 3.6.7 Recirculation Spray (RS) System . . 3.6.7-1 3.6.8 Chemical Addition System ..... 3.6.8-1 3.7 PLANT SYSTEMS ................... 3.7.1-1 3.7.1 Main Steam Safety Valves (MSSVs) 3.7.1-1 3.7.2 Main SteamTrip Valves (MSTVs) ,.. .3.7.2-1 3.7.3 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs),

Main Feedwater Regulating Valves (MFRVs),

and Main Feedwater Regulating Bypass Valves (MFRBVs) . . . . . . . . . . . . . . . . . . . *.3.7.3-1 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs) . . . . . . . . . . . . . . . . . .. 3.7.4-1 3.7.5 Auxiliary Feedwater (AFW) System ....... . . .3.7.5-1 3.7.6 Emergency Condensate Storage Tank (ECST) . . . *. .. 3.7.6-1 3.7.7 Secondary Specific Activity .............. . . . 3.7.7-1 3.7.8 Service Water (SW) System .... ........... . . .3.7.8-1 3.7.9 Ultimate Heat Sink (UHS) ........... . . .3.7.9-1 North Anna Units 1 and 2 ii 248, 228

Definitions 1.1 1.1 Definitions E-AVERAGE DISINTEGRATION E shall be the average (weighted in proportion to 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 > 15 minutes, making up at least 95% of the total noniodine activity in the coolant.

ENGINEERED SAFETY The ESF RESPONSE TIME shall be that time interval FEATURE (ESF) RESPONSE from when the monitored parameter exceeds its ESF TIME 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 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)

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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 all master relays in the channel required for channel OPERABILITY and verifying the OPERABILITY of each required master relay. The MASTER RELAY TEST shall include a continuity check of each associated required slave relay. The MASTER RELAY TEST may be performed by means of any series of sequential, overlapping, or total steps.

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 wi.th 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:

a. Described in Chapter 14, Initial Tests and Operation, of the UFSAR; (continued)

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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;

d. 150 gallons per day primary to secondary LEAKAGE through any one steam generator (SG). I 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. I limits for reasons other than pressure boundary LEAKAGE or primary to secondary LEAKAGE.

B. Required Action and 8.1 Be in MODE 3. 6 hours0.25 days <br />0.0357 weeks <br />0.00822 months <br /> associated Completion Time of Condition A AND not 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.

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

1. 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.

2. Not applicable to primary to secondary LEAKAGE.

Verify RCS operational LEAKAGE is within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> limits by performance of RCS water inventory balance.

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 gallons per day through any one SG.

72 hours3 days <br />0.429 weeks <br />0.0986 months <br /> I North Anna Units I and 2 3.4.13-2 248, 228

SG Tube Integrity 3.4.20 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.20 Steam Generator (SG) Tube Integrity LCO 3.4.20 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

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

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 7 days satisfying the tube of the affected repair criteria and tube(s) is maintained not plugged in until the next accordance with the refueling outage or SG Steam Generator tube inspection.

Program.

AND A.2 Plug the affected Prior to tube(s) in accordance entering MODE 4 with the Steam following the Generator Program. next refueling outage or SG tube inspection North Anna Units 1 and 2 3.4.20-1 248, 228

SG Tube Integrity 3.4.20 ACTIONS_

CONDITION REQUIRED ACTION COMPLETION TIME 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 AND not 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.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.20.1 Verify SG tube integrity in accordance with In accordance the Steam Generator Program. with the Steam Generator Program SR 3.4.20.2 Verify that each inspected SG tube that Prior to satisfies the tube repair criteria is entering MODE 4 plugged in accordance with the Steam following a SG Generator Program. tube inspection North Anna Units 1 and 2 3.4.20-2 248, 228

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.7 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 the ASME Code for Operation and Maintenance of Nuclear Power Plants and applicable Addenda as follows:

ASME Code for Operation and Maintenance of Nuclear Power Plants and applicable Addenda Required Frequencies for.

terminology for inservice performing 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 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 Code for Operation and Maintenance of Nuclear Power Plants shall be construed to supersede the requirements of any TS.

5.5.8 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 a SG inspection outage, as determined from the inservice (continued)

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Programs and. Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) Program

a. (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 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.

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. Leakage is not to exceed 1 gpm for all SGs.

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

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Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 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.

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Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.8 Steam Generator (SG) Program (continued)

e. Provisions for monitoring operational primary to secondary LEAKAGE.

5.5.9 Secondary Water Chemistry Program This program provides controls for monitoring secondary water chemistry to inhibit SG tube degradation and low pressure turbine disc stress corrosion cracking. 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 discharge of the condensate pumps 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.

5.5.10 Ventilation Filter Testing Program (VFTP)

A program shall be established to implement the following required testing of Engineered Safety Feature (ESF) filter ventilation systems in general conformance with the frequencies and requirements of Regulatory Positions C.5.a, C.5.c, C.5.d, and C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, and ANSI N510-1975.

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 < 1.0% when tested in accordance (continued)

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Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Ventilation Filter Testing Program (VFTP)

a. (continued) with Regulatory Positions C.5.a and C.5.c of Regulatory Guide 1.52, Revision 2, March 1978, and ANSI N510-1975 at the system flowrate specified below.

ESF Ventilation System Flowrate Main Control Room/Emergency Switchgear 1000 +/- 10% cfm Room (MCR/ESGR) Emergency Ventilation System (EVS)

Emergency Core Cooling System (ECCS) Nominal Pump Room Exhaust Air Cleanup System accident flow (PREACS) for a single train actuation Nominal accident flow for a single train actuation is greater than the minimum required cooling flow for ECCS equipment operation, and S 39,200 cfm, which is the maximum flow rate providing an adequate residence time within the charcoal adsorber.

b. Demonstrate for each of the ESF systems that an inplace test of the charcoal adsorber shows a penetration and system bypass

< 1.0% when tested in accordance with Regulatory Positions C.5.a and C.5.d of Regulatory Guide 1.52, Revision 2, March 1978, and ANSI N510-1975 at the system flowrate specified below.

ESF Ventilation System Flowrate MCR/ESGR EVS 1000 +/- 10% cfm ECCS PREACS Nominal accident flow for a single train actuation Nominal accident flow for a single train actuation is greater than the minimum required cooling flow for ECCS equipment operation, and

• 39,200 cfm, which is the maximum flow rate providing an adequate residence time within the charcoal adsorber.

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 Position C.6.b of Regulatory Guide 1.52, Revision 2, March 1978, shows the methyl iodide penetration less than the (continued)

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Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Ventilation Filter Testing Program (VFTP)

c. (continued) value specified below when tested in accordance with ASTM D3803-1989 at a temperature of 30'C (86°F) and relative humidity specified below.

ESF Ventilation System Penetration RH MCR/ESGR EVS 2.5% 70%

ECCS PREACS 5% 70%

d. Demonstrate for each of the ESF systems that the pressure drop across the combined HEPA filters, the prefilters, and the charcoal adsorbers is less than the value specified below when tested in accordance with ANSI N510-1975 at the system flowrate specified below.

ESF Ventilation System Delta P Flowrate MCR/ESGR EVS 4 inches W.G. 1000 +/- 10% cfm ECCS PREACS 5 inches W.G.  : 39,200 cfm

e. Demonstrate that the heaters for each of the ESF systems dissipate Ž the value specified below when tested in accordance with ASME N510-1975.

ESF Ventilation System Wattage MCR/ESGR EVS 3.5 kW The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

5.5.11 Explosive Gas and Storage Tank Radioactivity Monitoring Program This program provides controls for potentially explosive gas mixtures contained in the Gaseous Waste System, the quantity of radioactivity contained in gas storage tanks, 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 (continued)

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Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.11 Explosive Gas and Storage Tank Radioactivity Monitoring Program (continued)

Failure". The liquid radwaste quantities shall be determined in accordance with Standard Review Plan, Section 15.7.3, "Postulated Radioactive Release due to Tank Failures".

The program shall include:

a. The limits for concentrations of hydrogen and oxygen in the Gaseous Waste 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 storage tank is less than the amount that would result in a whole body exposure of Ž 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 each of the following outdoor 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 areadrains liquid radwaste ion exchanger system is less than the amount that would result in concentrations greater than the limits of 10 CFR 20, Appendix B, Table 2, Column 2, excluding tritium, at the nearest potable water supply and the nearest surface water supply in an unrestricted area, in the event of an uncontrolled release of the tanks' contents:

1. Refueling Water Storage Tank;

2. Casing Cooling Storage Tank;

3. PG Water Storage Tank;

4. Boron Recovery Test Tank; and

5. Any Outside Temporary Tank.

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.

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Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 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,

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

3. water and sediment

• 0.05%.

b. Within 31 days following addition of the new fuel oil to storage tanks verify that the properties of the new fuel oil, other than those addressed in a. above, are within limits for ASTM 2D fuel oil;

c. Total particulate concentration of the stored fuel oil is

• 10 mg/l when tested every 92 days in accordance with ASTM D-2276, Method A-2 or A-3; and

d. The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Diesel Fuel Oil Testing Program testing Frequencies.

5.5.13 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 (continued)

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Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Technical Specifications (TS) Bases Control Program (continued)

b. (continued)

2. a change to the UFSAR 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 UFSAR.

d. Proposed changes that meet the criteria of Specification 5.5.13b 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).

5.5.14 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, no concurrent loss of offsite power or loss of onsite diesel generator(s), a safety function assumed in the accident (continued)

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Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.14 Safety Function Determination Program (SFDP) (continued) analysis cannot be performed. For the purpose of this program, a loss of safety function may exist when a support system is inoperable, and:

a. A required system redundant to the system(s) supported by the inoperable support system is also inoperable; or

b. A required system redundant to the system(s) in turn supported by the inoperable supported system is also inoperable; or

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

The SFDP identifies where a loss of safety function exists. If a loss of safety function is determined to exist by this program, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered. When a loss of safety function is caused by the inoperability of a single Technical Specification support system, the appropriate Conditions and Required Actions to enter are those of the support system.

5.5.15 Containment Leakage Rate Testing Program

a. A program shall establish 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-Test Program," dated September 1995 as modified by the following exception:

NEI 94-01-1995, Section 9.2.3: The first Unit 1 Type A test -

performed after the April 3, 1993 Type A test shall be performed no later than April 2, 2008.

b. The calculated peak containment internal pressure for the design basis loss of coolant accident, Pa, is 44.1 psig. The containment design pressure is 45 psig.

c. The maximum allowable containment leakage rate, La, at Pa, shall be 0.1% of containment air weight per day.

(continued)

North Anna Units 1 and 2 5.5-14 248,228

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.15 Containment Leakage Rate Testing Program (continued)

d. Leakage Rate acceptance criteria are:

1. Prior to entering a MODE where containment OPERABILITY is required, the containment leakage rate acceptance criteria are:

• 0.60 La for the Type B and Type C tests on a Maximum Path Basis and : 0.75 La for Type A tests.

During operation where containment OPERABILITY is required, the containment leakage rate acceptance criteria are:

1.0 La for overall containment leakage rate and

• 0.60 La for the Type B and Type C tests on a Minimum Path Basis.

2. Overall air lock leakage rate testing acceptance criterion is

• 0.05 La when tested at Ž Pa-

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

f. Nothing in these Technical Specifications shall be construed to modify the testing Frequencies required by 10 CFR 50, Appendix J.

North Anna Units I and 2 5.5-15 248,228

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.5 CORE OPERATING LIMITS REPORT (COLR)

b. (continued)

14. BAW-10199P-A, "The BWU Critical Heat Flux Correlations."

15. BAW-10170P-A, "Statistical Core Design for Mixing Vane Cores."

16. EMF-2103 (P)(A), "Realistic Large Break LOCA Methodology for Pressurized Water Reactors."

17. EMF-96-029 (P)(A), "Reactor Analysis System for PWRs."

18. BAW-10168P-A, "RSG LOCA - BWNT Loss-of-Coolant Accident Evaluation Model for Recirculating Steam Generator Plants,"

Volume II only (SBLOCA models).

19. DOM-NAF-2-A, "Reactor Core Thermal-Hydraulics Using the VIPRE-D Computer Code," including Appendix A, "Qualification of the F-ANP BWU CHF Correlations in the Dominion VIPRE-D Computer Code."

c. The core operating limits shall be determined such that all applicable limits (e.g., fuel thermal mechanical limits, core thermal hydraulic limits, Emergency Core Cooling Systems (ECCS) limits, nuclear limits such as SDM, transient analysis limits, and accident analysis limits) of the safety analysis are met.

d. The COLR, including any midcycle revisions or supplements, shall be provided upon issuance for each reload cycle to the NRC.

5.6.6 PAM Report When a report is required by Condition B of LCO 3.3.3, "Post Accident Monitoring (PAM) Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

248,228 North Anna Units 1 and 2 5.6-4

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.7 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 5.5.8, "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, and

h. The effective plugging percentage for all plugging in each SG.

248,228 North Anna Units 1 and 2 5.6-5

TECHNICAL SPECIFICATIONS BASES TABLE OF CONTENTS B 3.4 REACTOR COOLANT. SYSTEM (RCS) (continued)

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 RCS Loop Isolation Valves ............ .B 3.4.17-1 B 3.4.18 RCS Isolated Loop Startup ............ .B 3.4.18-1 B 3.4.19 RCS Loops-Test Exceptions ............. .B 3.4.19-1 B 3.4.20 Steam Generator (SG) Tube Integrity .... .B 3.4.20-1 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 3.5.3-1i 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 Boron Injection Tank (BIT) ........ 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 Quench Spray (QS) System ' B 3.6.6-1 B 3.6.7 Recirculation Spray (RS) System B 3.6.7-1 B 3.6.8 Chemical Addition System . . . B 3.6.8-1 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 Trip Valves (MSTVs) ... B 3.7.2-1 B 3.7.3 Main Feedwater Isolation Valves (MFIVs), Main Feedwater Pump Discharge Valves (MFPDVs),

Main Feedwater Regulating Valves (MFRVs),

and Main Feedwater Regulating Bypass Valves (MFRBVs) .................... B 3.7.3-1 B 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs) . . . . . . . . . . . . . . . B 3.7.4-1 B 3.7.5 Auxiliary Feedwater (AFW) System ...... B 3.7.5-1 B 3.7.6 Emergency Condensate Storage Tank (ECST) . . B 3.7.6-1 B 3.7.7 Secondary Specific Activity ............ B 3.7.7-1 B 3.7.8 Service Water (SW) System .............. B 3.7.8-1 B 3.7.9 Ultimate Heat Sink (UHS) .......... B 3.7.9-1 B 3.7.10 Main Control Room/Emergency Switchgear Room (MCR/ ESGR) Emergency Ventilation System (EVS)-MODES 1, 2, 3, and 4 ....... . B 3.7.10-1 B 3.7.11 Main Control Room/Emergency Switchgear Room (MCR/ESGR) Air Conditioning System (ACS) .B 3.7.11-1 North Anna Units I and 2 ii 248, 228

RCS Loops-MODES 1 and 2 B 3.4.4 BASES APPLICABLE Both transient and steady state analyses have been performed SAFETY ANALYSES to establish the effect of flow on the departure from (continued) nucleate boiling (DNB). The transient and accident analyses for the unit have been performed assuming three RCS loops are in operation. The majority of the unit 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 flow, single reactor coolant pump locked rotor, partial loss of forced reactor flow, and rod withdrawal events (Ref. 1).

The DNB analyses assume normal three loop operation.

Uncertainties in key unit operating parameters, nuclear and thermal parameters, and fuel fabrication parameters are considered statistically such that there is at least a 95 percent probability that DNB will not occur for the limiting power rod. Key unit parameter uncertainties are used to determine the unit departure from nucleate boiling ratio (DNBR) uncertainty. This DNBR uncertainty, combined with the DNBR limit, establishes a design DNBR value which must be met in unit safety analyses and is used to determine the pressure and temperature Safety Limit (SL). Since the parameter uncertainties are considered in determining the design DNBR value, the unit safety analyses are performed using values of input parameters without uncertainties. Therefore, nominal operating values for reactor coolant flow are used in the accident analyses.

The unit is designed to operate with all RCS loops in operation to maintain DNBR above the limit 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 I 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 DNBR, 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.

North Anna Units 1 and 2 B 3.4.4-2 248,228

RCS Loops-MODE 3 B 3.4.5 BASE S LCO Utilization of the Note is permitted provided the following (continued) 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 with coolant at boron concentrations less than required to ensure the SDM of LCO 3.1.1,,

thereby maintaining the margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure the SDM is maintained 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 10OF 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. 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.

Operation in other MODES is covered by:

LC0.3.4.4, "RCS Loops-MODES 1 and 2";

LCO 3.4.6, "RCS Loops-MODE 4";

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

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

LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level" (MODE 6); and LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level" (MODE 6).

ACTIONS A.1 If one required RCS loop is inoperable, redundancy for heat removal is lost. The Required Action is restoration of the required RCS loop to OPERABLE status within the Completion (continued)

North Anna Units I and 2 B 3.4.5-3 248,228

RCS Loops-MODE 3 B 3.4.5 BASES ACTIONS A.1 (continued)

Time of 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />. This time allowance is a justified period to be without the redundant, nonoperating loop because a single loop in operation has a heat transfer capability greater than that needed to remove the decay heat produced in the reactor core and because of the low probability of a failure in the remaining loop occurring during this period.

B.1 If restoration is not possible within 72 hours3 days <br />0.429 weeks <br />0.0986 months <br />, the unit must be brought to MODE 4. In MODE 4, the unit may be placed on the Residual Heat Removal System. The additional Completion Time of 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> is compatible with required operations to achieve cooldown and depressurization from the existing unit conditions in an orderly manner and without challenging unit systems.

C.1, C.2, and C.3 If two required RCS loops are inoperable or a required RCS loop is not in operation, except as during conditions permitted by the Note in the LCO section, place the Rod Control System in a condition incapable of rod withdrawal (e.g., all CRDMs must be de-energized by opening the RTBs or de-energizing the MG sets). All operations involving introduction of coolant into the RCS with boron concentration less than required to meet the minimum SDM of LCO 3.1.1 must be suspended, and action to restore one of the RCS loops to OPERABLE status and operation must be initiated. Boron dilution requires forced circulation for proper mixing, and opening the RTBs or de-energizing the MG sets removes the possibility of an inadvertent rod withdrawal. Suspending the introduction of coolant into the RCS of coolant with boron concentration less than required to meet the minimum SDM of LCO 3.1.1 is required to assure continued safe operation. With coolant added without forced circulation, unmixed coolant could be introduced to the core, however coolant added with boron concentration meeting the minimum SDM maintains acceptable margin to subcritical operations. The immediate Completion Time reflects the importance of maintaining operation for heat removal. The action to restore must be continued until one loop is restored to OPERABLE status and operation.

248,228 North Anna Units 1 and 2 B 3.4.5-4

RCS Loops-MODE 4 B 3.4.6 BASES LCO _<280'F. This restraint is to prevent a low temperature (continued) overpressure event due to a thermal transient when an RCP is started.

An OPERABLE RCS loop is comprised of an OPERABLE RCP and an OPERABLE SG, which has the minimum water level specified in I SR 3.4.6.2.

Similarly for the RHR System, an OPERABLE RHR loop is comprised of 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 provide redundancy for heat removal.

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 Lobps-MODE 5, Loops Filled";

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

LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level" (MODE 6); and LCO 3.9.6, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level" (MODE 6).

ACTIONS A.1 If one required loop is 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.

North Anna Units 1 and 2 B 3.4.6-3 248,228

RCS Loops-MODE 5, Loops Filled B 3.4.7 BASES LCO Utilization of Note 1 is permitted provided the following (continued) 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 with coolant at boron concentrations less than required to meet the SDM of LCO 3.1.1, therefore maintaining the margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure the SDM is maintained 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 10OF 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 before the start of a reactor coolant pump (RCP) with an RCS cold leg temperature

• 280'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 with circulation provided by an RCP.

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.

North Anna Units 1 and 2 B 3.4.7-3 248,228

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses SAFETY ANALYSES do not address operational LEAKAGE. However, other operational LEAKAGE is related to the safety analyses for 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 one gallon per minute or increases to one gallon per minute 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 gallons per day is significantly less than the conditions assumed in the safety analysis.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a main steam line break (MSLB) accident. 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 UFSAR (Ref.,..3) analysis for SGTR assumes the contaminated secondary fluid is released via power operated relief valves or safety valves. The source term in the primary system coolant is transported to the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam to the environment for 30 minutes until the generator is manually isolated. The I gpm primary to secondary LEAKAGE transports the source term to the unaffected steam generators. Releases continue through the unaffected steam generators until the Residual Heat Removal System is placed in service.

The MSLB is less limiting for site radiation releases than the SGTR. The safety analysis for the MSLB accident assumes 1 gpm primary to secondary LEAKAGE as an initial condition.

The dose consequences resulting from the MSLB and SGTR accidents are within the limits defined in the staff approved licensing basis.

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

North Anna Units 1 and 2 B 3.4. 13-2 248,228

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 Secondary LEAKAGE through Any One SG The limit of 150 gallons per day per 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 (continued)

North Anna Units 1 and 2 B 3.4.13-3 248, 228

RCS Operational LEAKAGE B 3.4.13 BASES LCO d. Primary to Secondary LEAKAGE through Any One SG (continued) 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.

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 I 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 LEAKAGE, 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 (continued) 248,228 North Anna Units 1 and 2 B 3.4.13-4

RCS Operational LEAKAGE B 3.4.13 BASES ACTIONS B.1 and B.2 (continued) 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 unitconditions from full power conditions in an orderly manner and without challenging unit systems. In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

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 RtS water inventory balance must be met with the reactor at steady state operating conditions (stable temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows). The surveillance is modified by two Notes. Note 1 states that this SR is not required to be performed until 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> after establishing steady state operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.

Steady state operation is required to perform a proper inventory balance since calculations during maneuvering are not useful. 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 I (continued)

North Anna Units I and 2 B 3.4.13-5 248,228

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.1 (continued)

REQUIREMENTS the containment sump level. 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 because LEAKAGE of 150 gallons per day 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.

SR 3.4.13.2 This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day 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 3.4.20, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day 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. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRI guidelines (Ref. 5).

North Anna Units 1 and 2 B 3.4.13-6 248,228

RCS Operational LEAKAGE B 3.4.13 BASES REFERENCES 1. UFSAR, Section 3.1.26.

2. Regulatory Guide 1.45, May 1973.

3. UFSAR, Chapter 15.

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

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

North Anna Units 1 and 2 B 3.4. 13-7 248,228

SG Tube Integrity B 3.4.20 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.20 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 5.5.8, "Steam Generator (SG) Program,"

requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.8, 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 5.5.8. Meeting the (continued) 248,228 North Anna Units I and 2 B 3.4.20-1

SG Tube Integrity B 3.4.20 BASES BACKGROUND SG performance criteria provides reasonable assurance of (continued) maintaining tube integrity at normal and accident conditions.

The processes used to meet the SG performance criteria are defined by the Steam Generator Program Guidelines (Ref. 1).

APPLICABLE The steam generator tube rupture (SGTR) accident is the SAFETY ANALYSES limiting basis event for SG tubes and avoiding a SGTR is the basis for this Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate of 1 gpm, which is conservative with respect 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 UFSAR analysis for SGTR assumes the contaminated secondary fluid is released via power operated relief valves or safety valves.

The source term in the primary system coolant is transported to the affected (ruptured) steam generator by the break flow. The affected steam generator discharges steam to the environment for 30 minutes until the generator is manually isolated. The I gpm primary to secondary LEAKAGE transports the source term to the unaffected steam generators. Releases continue through the unaffected steam generators until the Residual Heat Removal System is placed in service.

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 I gallon per minute or is assumed to increase to I gallon per minute 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 50.67 (Ref. 3) or RG 1.183 (Ref. 4), as appropriate.

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

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SG Tube Integrity B 3.4.20 BASES 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.

In the context of this Specification, a SG tube is defined as the entire 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 5.5.8, "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." The structural integrity performance criterion provides guidance on assessing loads that have a significant effect on burst or collapse. In that context, the term "significant" is defined as "An accident loading condition other than differential pressure is considered significant (continued)

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SG Tube Integrity B 3.4.20 BAS ES LCO when the addition of such loads in the assessment of the (continued) structural integrity performance criterion could cause a lower structural limit or limiting burst/collapse condition to be established." For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary loads. For circumferential degradation, the classification of axial thermal loads as primary or secondary loads will be evaluated on a case-by-case basis. The division between primary and secondary classifications will be based on detailed analysis and/or testing.

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 III, Subsection NB (Ref. 5) and Draft Regulatory Guide 1.121 (Ref. 6).

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 gpm. The accident induced leakage rate includes any primary to secondary 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 gallons per day.

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 SG 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.

(continued)

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SG Tube Integrity B 3.4.20 BASES APPLICABILITY SG integrity limits are not provided in MODES 5 and 6 since (continued) RCS conditions are far less challenging than 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 separate Conditions entry is permitted 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 3.4.20.2. An evaluation of SG tube integrity of the 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 refueling outage or 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 (continued)

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SG Tube Integrity B 3.4.20 BASES ACTIONS A.1 and A.2 (continued) 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.hours.

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.

SURVEILLANCE SR 3.4.20.1 REQUIREMENTS 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 North Anna Units I and 2 B 3.4.20-6 248,228

SG Tube Integrity B 3.4.20 BASES SURVEILLANCE SR 3.4.20.1 (continued)

REQUIREMENTS function of degradation morphology, non-destructive examination (NDE) technique capabilities, and inspection locations.

The Steam Generator Program defines the Frequency of SR 3.4.20.1. The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 7). 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 5.5.8 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.20.2 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 5.5.8 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 provides 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. 10 CFR 50.67.

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SG Tube Integrity B 3.4.20 BASES REFERENCES 4. RG 1.183, July 2000.

(continued)

5. ASME Boiler and Pressure Vessel Code,Section III, Subsection NB.

6. Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

7. EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines."

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