Text

Technical Specifications, Issuance of Amendments Regarding Steam Generator Tube Integrity
	ML070930372
Person / Time
Site:	Oconee
Issue date:	04/02/2007
From:	; NRC/NRR/ADRO/DORL/LPLII-1
To:	;
	Olshan L N, NRR/DORL, 415-1419
Shared Package
ML070110302	List: ML070110314; ML070930372;
References
	TAC MD2038, TAC MD2039, TAC MD2040, TAC MD2043, TAC MD2044, TAC MD2045
	Download: ML070930372 (47)
	v • d • e

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.

A. Maximum Power Level The licensee Is authorized to operate the facility at steady state reactor core power levels not In excess of 2568 megawatts thermal.

B. Technicai Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 355 are hereby Incorporated In the license. The licensee shall operate the facility Inaccordance with the Technical Specifications.

C. This license Is subject to the following antitrust conditions:

Applicant makes the commitments contained herein, recognizing that bulk power supply arrangements between neighboring entities normally tend to serve the public interest In addition, where there are net benefits to all participants, such arrangements also serve the best Interests of each of the participants. Among the benefits of such transactions are Increased electric system reliability, a reduction In the cost of electric power, and minimization of the environmental effects of the production and sale of electricity.

Any particular bulk power supply transaction may afford greater benefits to one participant than to another. The benefits realized by a small system may be proportionately greater than those realized by a larger system. The relative benefits to be derived by the parties from a proposed transaction, however, should not be controlling upon a decision with respect to the desirability of participating in the transaction. Accordingly, applicant will enter Into proposed bulk power transactions of the types hereinafter described which, on balance, provide net benefits to applicant There are net benefits In a transaction Ifapplicant recovers the cost of the transaction (as defined In¶1 (d) hereof) and there is no demonstrable net detriment to applicant arising from that transaction.

1. As used herein:

(a) "Bulk Power' means electric power and any attendant energy, supplied or made available at transmission or sub-ransmisslon voltage by one electric system to another.

(b) "Nelghboring Entity" means a private or public corporation, a governmental agency or authority, a municipality, a cooperative, or a lawful association of any of the foregoing owning or operating, or Renewed License No. DPR-38 Amendment No. 355

December 27, 1984; December 5, 1988; and August 21, 1989 subject to the following provision:

The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

E. Physical Protection Duke Power Company LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains safeguards information protected under 10 CFR 73.21, is entitled: "Duke Energy Physical Security Plan" submitted by letter dated September 8, 2004, and supplemented on September 30, 2004, October 15, 2004, October 21, 2004, and October 27, 2004.

F. In the update to the UFSAR required pursuant to 10 CFR 50.71 (e)(4) scheduled for July, 2001, the licensee shall update the UFSAR to include the UFSAR supplement submitted pursuant to 10 CFR 54.21(d) as revised on March 27, 2000. Until the UFSAR update is complete, the licensee may make changes to the programs described in its UFSAR supplement without prior Commission approval, provided that the licensee evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

G. The licensee's UFSAR supplement submitted pursuant to 10 CFR 54.21(d), as revised on March 27, 2000, describes certain future inspection activities to be completed before the period of extended operation. The licensee shall complete these activities no later than February 6, 2013.

4. This renewed license is effective as of the date of issuance and shall expire at midnight on February 6, 2033.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By Roy P. Zimmerman Roy P. Zimmerman, Acting Director Office of Nuclear Reactor Regulation

Attachment:

1) Appendix A - Technical Specifications Renewed License No. DPR-38 Date of Issuance: May 23, 2000 Renewed License No. DPR-38 Amendment No. 355

Part 70; is subject to all applicable provisions of the Act and to the nrles, regulations, and orders of the Commission now or hereafter in effect; and Issubject to the additional conditions specified or incorporated below:.

A. Maximum Power Level The licensee is authorized to operate the facility at steady state reactor core power levels not In excess of 2568 megawatts thermal.

B. Techrncal Specifications The Technical Specifications contained InAppendix A,as revised through Amendment No. 357 *irehereby Incorporated Inthe license. The licensee shall operate the facility In accordance with the Technical Specifications; C. This license Is subject to the following antitrust conditions:

Applicant makes the commitments contained herein, recognizing that bulk power supply arrangements between neighboring entities normally tend to serve the public interest. In addition, where there are net benefits to all participants, such arrangements also serve the best Interests of each of the participants. Among the benefits of such transactions are Increased electric system reliability, a reduction in the cost of electric power, and minimization of the environmental effects of the production and sale of electricity.

Any particular bulk power supply transaction may afford greater benefits to one participant than to another. The benefits realized by a small system may be proportionately greater than those realized by a larger system. The relative benefits to be derived by the parties from a proposed transaction, however, should not be controlling upon a decision with respect to the desirability of participating in the transaction. Accordingly, applicant will enter into proposed bulk power transactions of the types hereinafter described which, on balance, provide net benefits to applicant There are net benefits In a transaction ifapplicant recovers the cost of the transaction (as defined In ¶1(d) hereof) and there Isno demonstrable net detriment to applicant arising from that transaction.

1. As used herein:

(a) 'Bulk Powern means electric power and any attendant energy, supplied or made available at transmission or sub-ransmission voltage by one electric system to another.

(b) "Neighboring Entity" means a private or public corporation, a governmental agency or authority, a municipality, a cooperative, or a lawful association of any of the foregoing owning or operating, or Renewed Ucense No. DPR-47 Amendment No. 357

December 27, 1984; December 5, 1988; and August 21, 1989 subject to the following provision:

The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

E. Physical Protection Duke Power Company LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains safeguards information protected under 10 CFR 73.21, is entitled: "Duke Energy Physical Security Plan" submitted by letter dated September 8, 2004, and supplemented on September 30, 2004, October 15, 2004, October 21, 2004, and October 27, 2004.

F. In the update to the UFSAR required pursuant to 10 CFR 50.71 (e)(4) scheduled for July, 2001, the licensee shall update the UFSAR to include the UFSAR supplement submitted pursuant to 10 CFR 54.21(d) as revised on March 27, 2000. Until the UFSAR update is complete, the licensee may make changes to the programs described in its UFSAR supplement without prior Commission approval, provided that the licensee evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

G. The licensee's UFSAR supplement submitted pursuant to 10 CFR 54.21(d), as revised on March 27, 2000, describes certain future inspection activities to be completed before the period of extended operation. The licensee shall complete these activities no later than February 6, 2013.

4. This renewed license is effective as of the date of issuance and shall expire at midnight on October 6, 2033.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By Roy P. Zimmerman Roy P. Zimmerman, Acting Director Office of Nuclear Reactor Regulation

Attachment:

1) Appendix A - Technical Specifications Renewed License No. DPR-47 Date of issuance: May 23, 2000 Renewed License No. DPR-47 Amendment No. 357

Part 70; Is subject to all applicable provisions of the Act and to the rules, regulations, and orders of the Commission now or hereafter Ineffect; and Is subject to the additional conditions specified or Incorporated below.

A. Maximum Power-Level The licensee Is authorized to operate the facility at steady state reactor core power levels not in excess of 2568 megawatts thermal.

B. Technical Specifications The Technical Soecifications contained InAppendix A. as revised through Amendment No..356 are hereby Incorporated in the license. The licensee shall operate the facility In accordance with the Technical Specifications.

C. This license Is subject to the following antitrust conditions:

Applicant makes the commitments contained herein, recognizing that bulk power supply arrangements between neighboring entities normally tend to serve the public interest. In addition, where there are net benefits to all participants, such arrangements also serve the best Interests of each of the participants. Among the benefits of such transactions are Increased electric system reliability, a reduction in the cost of electric power, and minimization of the environmental effects of the production and sale of electricity.

Any particular bulk power supply transaction may afford greater benefits to one participant than to another. The benefits realized by a small system may be proportionately greater than those realized by.a larger system. The relative benefits to be derived by the parties from a proposed transaction, however, should not be controlling upon a decision with respect to the desirability of participating In the transacdon. Accordingly, applicant will enter Into proposed bulk power transactions of the types hereinafter described which, on balance, provide net benefits to applicanL There are net benefits in a transaction Ifapplicant recovers the cost of the transaction (as defined in¶11(d) hereof) and there is no demonstrable net detriment to applicant arising from that transaction.

1. As used herein:

(a) "Bulk Power" means electric power and any attendant energy, supplied or made available at transmission or sub-transmission voltage by one electric system to another.

(b) "Neighboring Entity" means a private or public corporation, a governmental agency or authority, a municipality, a cooperative, or a lawful association of any of the foregoing owning or operating, or Renewed License No. DPR-55 Amendment No. 356

December 27, 1984; December 5, 1988; and August 21, 1989 subject to the following provision:

The licensee may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

E. Physical Protection Duke Power Company LLC shall fully implement and maintain in effect all provisions of the Commission-approved physical security, training and qualification and safeguards contingency plans including amendments made pursuant to provisions of the Miscellaneous Amendments and Search Requirements revisions to 10 CFR 73.55 (51 FR 27817 and 27822) and to the authority of 10 CFR 50.90 and 10 CFR 50.54(p). The combined set of plans, which contains safeguards information protected under 10 CFR 73.21, is entitled: "Duke Energy Physical Security Plan" submitted by letter dated September 8, 2004, and supplemented on September 30, 2004, October 15, 2004, October 21, 2004, and October 27, 2004.

F. In the update to the UFSAR required pursuant to 10 CFR 50.71 (e)(4) scheduled for July, 2001, the licensee shall update the UFSAR to include the UFSAR supplement submitted pursuant to 10 CFR 54.21(d) as revised on March 27, 2000. Until the UFSAR update is complete, the licensee may make changes to the programs described in its UFSAR supplement without prior Commission approval, provided that the licensee evaluates each such change pursuant to the criteria set forth in 10 CFR 50.59 and otherwise complies with the requirements in that section.

G. The licensee's UFSAR supplement submitted pursuant to 10 CFR 54.21 (d), as revised on March 27, 2000, describes certain future inspection activities to be completed before the period of extended operation. The licensee shall complete these activities no later than February 6, 2013.

4. This renewed license is effective as of the date of issuance and shall expire at midnight on July 19, 2034.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By Roy P. Zimmerman Roy P. Zimmerman, Acting Director Office of Nuclear Reactor Regulation

Attachment:

1) Appendix A - Technical Specifications Renewed License No. DPR-55 Date of issuance: May 23, 2000 Renewed License No. DPR-55 Amendment No. 356

TABLE OF CONTENTS 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 RCS Specific Activity .......................................................................... 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 Steam Generator (SG) Tube Integrity ................................................ 3.4.16-1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) ................................ 3.5.1-1 3.5.1 Core Flood Tanks (CFTs) ................................................................... 3.5.1-1 3.5.2 High Pressure Injection ...................................................................... 3.5.2-1 3.5.3 Low Pressure Injection ...................................................................... 3.5.3-1 3.5.4 Borated Water Storage Tank (BWST) ............................................... 3.5.4-1 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 Reactor Building Spray and Cooling System ...................................... 3.6.5-1 3.7 PLANT SYSTEMS ...................................................................................... 3.7.1-1 3.7.1 Main Steam Relief Valves (MSRVs) ................................................... 3.7.1-1 3.7.2 Turbine Stop Valves (TSVs) ............................................................... 3.7.2-1 3.7.3 Main Feedwater Control Valves (MFCVs), and Startup Feedwater Control Valves (SFCVs) ............................................. 3.7.3-1 3.7.4 Atmospheric Dump Valve (ADV) Flow Paths ..................................... 3.7.4-1 3.7.5 Emergency Feedwater (EFW) System ............................................... 3.7.5-1 3.7.6 Upper Surge Tank (UST) and Hotwell (HW) ...................................... 3.7.6-1 3.7.7 Low Pressure Service Water (LPSW) System ................................... 3.7.7-1 3.7.8 Emergency Condenser Circulating Water (ECCW) ........................... 3.7.8-1 3.7.9 Control Room Ventilation System (CRVS) Booster Fans ................................................................... 3.7.9-1 3.7.10 Not Used ............... ...... -.3.7.10-1 3.7.11 Spent Fuel Pool Water Level .............................................................. 3.7.11-1 3.7.12 Spent Fuel Pool Boron Concentration .............. ......... ......................... 3.7.12-1 3.7.13 Fuel Assembly Storage ...................................................................... 3.7.13-1 OCONEE UNITS 1, 2, & 3 iii Amendment Nos. 3 5 5 , 357, & 356 1

TABLE OF CONTENTS 5.2 O rganization ......................................... ...................................................... 5.0-2 5.3 Station Staff Q ualifications ........................................................................ 5.0-5 5.4 Procedures ................................................................................................ 5.0-6 5.5 Program s and Manuals ............................................................................. 5.0-7 5.6 Reporting Requirem ents ............................................................................ 5.0-23 OCONEE UNITS 1, 2, & 3 V Amendment Nos. 355,357,& 356 I

TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS) ............................................... B 3.4.1-1 B 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits ........................................ B 3.4.1-1 B 3.4.2 RCS Minimum Temperature for Criticality .................................... B 3.4.2-1 B 3.4.3 RCS Pressure and Temperature (P/T) Limits .............................. B 3.4.3-1 B 3.4.4 RCS Loops - MODES 1 and 2 ..................................................... B 3.4.4-1 B 3.4.5 RCS Loops - MODE 3 ................................................................. B 3.4.5-1 B 3.4.6 RCS Loops - MODE 4 ................................................................. B 3.4.6-1 B 3.4.7 RCS Loops - MODE 5, Loops Filled ............................................ B 3.4.7-1 B 3.4.8 RCS Loops - MODE 5, Loops Not Filled ..................................... B 3.4.8-1 B 3.4.9 Pressurizer ................................................................................... B 3.4.9-1 B 3.4.10 Pressurizer Safety Valves ............................................................ B 3.4.10-1 B 3.4.11 RCS Specific Activity ................................................................... B 3.4.11-1 B 3.4.12 Low Temperature Overpressure Protection (LTOP)

S ystem .................................................................................... 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 Steam Generator (SG) Tube Integrity .......................................... B 3.4.16-1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) .......................... B 3.5.1-1 B 3.5.1 Core Flood Tanks (CFTs) ............................................................. B 3.5.1-1 B 3.5.2 High Pressure Injection (HPI) ..................................... I................. B 3.5.2-1 B 3.5.3 Low Pressure Injection (LPI) ....................................................... B 3.5.3-1 B 3.5.4 Borated Water Storage Tank (BWST) .................. B 3.5.4-1 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 Reactor Building Spray and Cooling System ................................ B 3.6.5-1 B 3.7 PLANT SYSTEMS ................................... B 3.7.1-1 B 3.7.1 Main Steam Relief Valves (MSRVs) ......................... !................... B 3.7.1-1 B 3.7.2 Turbine Stop Valves (TSVs) ......................... B 3.7.2-1 B 3.7.3 Main Feedwater Control Valves (MFCVs), and Startup Feedwater Control Valves (SFCVs) ........................................ B 3.7.3-1 B 3.7.4 Atmospheric Dump Valve (ADV) Flow Paths ............................... B 3.7.4-1 B 3.7.5 Emergency Feedwater (EFW) System ......................................... B 3.7.5-1 B 3.7.6 Upper Surge Tank (UST) and Hotwell (HW) .... .......... B 3.7.6-1 B 3.7.7 Low Pressure Service Water (LPSW) System ............................. B 3.7.7-1 B 3.7.8 Emergency Condenser Circulating Water (ECCW) ..................... B 3.7.8-1 OCONEE UNITS 1, 2, & 3 iii Amendment Nos. 355,357 & 356

Definitions 1.1 1.1 Definitions (continued)

E -AVERAGE E shall be the average (weighted in proportion DISINTEGRATION ENERGY to 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 > 30 minutes, making up at least 95% of the total noniodine activity in the coolant.

LEAKAGE LEAKAGE shall be:

a. Identified LEAKAGE

1. LEAKAGE, such as that from pump seals or valve packing (except 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);

b. Unidentified LEAKAGE All LEAKAGE (except RCP seal water injection or leakoff) that is not identified LEAKAGE.

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

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.

OCONEE UNITS 1, 2, & 3 1.1 -3 Amendment Nos. 355,357,& 356

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

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and I

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 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months LEAKAGE not within within limits.

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

(continued)

OCONEE UNITS 1, 2, & 3 3.4.13-1 Amendment Nos. 355,357,& 356

RCS Operational LEAKAGE 3.4.13 I

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR Pressure boundary LEAKAGE exists.

OR Primary to secondary LEAKAGE not within limit.

OCONEE UNITS 1, 2, & 3 3.4.13-2 Amendment Nos. 355,357,& 356

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

1. Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

2. Not applicable to primary to secondary LEAKAGE.

Evaluate RCS Operational LEAKAGE. 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.13.2 ------------------ NOTE ---------------- 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation.

Verify primary to secondary LEAKAGE is

< 150 gallons per day through any one SG. I OCONEE UNITS 1, 2, & 3 3.4.13-3 Amendment Nos. 355,357,& 356

SG Tube Integrity 3.4.16 I 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.16 Steam Generator (SG) Tube Integrity LCO 3.4.16 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 of 7 days satisfying the tube the affected tube(s) is repair criteria and not maintained until the plugged in accordance next refueling outage with the Steam or SG tube inspection.

Generator Program.

AND A.2 Plug the affected Prior to entering MODE 4 tube(s) in accordance following the next with the Steam refueling outage or SG Generator Program. tube inspection B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR SG tube integrity not maintained.

OCONEE UNITS 1, 2, & 3 .3.4.16-1 Amendment Nos. 355,357,& 356

SG Tube Integrity 3.4.16 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.16.1 Verify SG tube integrity in accordance with In accordance with the the Steam Generator Program. Steam Generator Program SR 3.4.16.2 Verify that each inspected SG tube that Prior to entering MODE 4 satisfies the tube repair criteria is plugged in following an SG tube accordance with the Steam Generator inspection Program.

OCONEE UNITS 1, 2, & 3 3.4-16-2 Amendment Nos. 355,357,& 356

Organization 5.2 5.0 ADMINISTRATIVE CONTROLS 5.2 Organization 5.2.1 Onsite and Offsite Organizations Onsite and offsite organizations shall be established for unit operation and corporate management, respectively. The onsite and offsite organizations shall include the positions for activities affecting safety of the nuclear power plant.

a. Lines of authority, responsibility, and communication shall be defined and established throughout highest management levels, intermediate levels, and all operating organization positions. These relationships shall be documented and updated, as appropriate, in organization charts, functional descriptions of departmental responsibilities and relationships, and job descriptions for key personnel positions, or in equivalent forms of documentation. These requirements shall be documented in the UFSAR;

b. The Station Manager shall be responsible for overall safe operation of the plant and shall have control over those onsite activities necessary for safe operation and maintenance of the plant;

c. The Vice-President, Oconee Nuclear Site, shall have corporate responsibility for overall plant nuclear safety and shall take any rheasures needed to ensure acceptable performance of the staff in operating, maintaining, and providing technical support to the plant to ensure nuclear safety;

d. The Group Vice President, Nuclear Generation Department, will be the Senior Nuclear Executive and have corporate responsibility for overall nuclear safety; and

e. The individuals who train the operating staff, carry out health physics, or perform quality assurance functions may report to the appropriate onsite manager; however, these individuals shall have sufficient organizational freedom to ensure their independence from operating pressures.

5.2.2 Station Staff

a. A non-licensed operator shall be onsite for each reactor containing fuel and an additional non-licensed operator shall be onsite for each control room from which a reactor is operating in MODES 1, 2, 3, or 4.

OCONEE UNITS 1, 2, & 3 5.0-2 Amendment Nos. 355,357,& 356

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Inservice Testing Program (continued)

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

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

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

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

5.5.10 Steam Generator (SG) Proaram I 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.

OCONEE UNITS 1, 2, & 3 5.0-13 Amendment Nos. 355,357,& 356 I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Steam Generator (SG) Program (continued)

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 150 gallons per day 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.

d. Provisions for SG tube inspections. Periodic 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 OCONEE UNITS 1, 2, & 3 5.0-14 Amendment Nos. 355,357,& 356

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.10 Steam Generator (SG) Progqram (continued) tube. In addition to meeting the requirements of d.1, d.2, and d.3 below, the inspection scope, inspection methods, and inspection intervals shall be such as to ensure that SG tube integrity is maintained until the next SG inspection.

An assessment of degradation shall be performed to determine the type and location of flaws to which the tubes may be susceptible and, based on this assessment, to determine which inspection methods need to be employed and at what locations.

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

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

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

e. Provisions for monitoring operational primary to secondary LEAKAGE.

OCONEE UNITS 1., 2, & 3 5.0-15 Amendment Nos. 355,357,& 356

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.11 Secondary Water Chemistry 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 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.

5.5.12 Ventilation Filter Testing Progqram (VFTP)

A program shall be established to implement the following required testing of filter ventilation systems at the frequencies specified in Regulatory Guide 1.52, Revision 2.

The VFTP is applicable to the Control Room Ventilation System (CRVS) Booster Fan Trains and the Spent Fuel Pool Ventilation System (SFPVS).

a. Demonstrate, for the CRVS Booster Fan Trains, that a DOP test of the HEPA filters shows > 99.5% removal when tested in accordance with ANSI N510-1975 at the system design flow rate +/- 10%.

b. Demonstrate, for the CRVS Booster Fan Trains, that a halogenated hydrocarbon test of the carbon adsorber shows _>99% removal when tested in accordance with ANSI N510-1975 at the system design flow rate

+/- 10%.

OCONEE UNITS 1, 2, & 3 5.0-16 Amendment Nos. 355,357,& 356 I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.12 Ventilation Filter Testing Pro-gram (VFTP) (continued)

c. Demonstrate, for the CRVS Booster Fan Trains and SFPVS, that a laboratory test of a sample of the carbon adsorber shows > 97.5% and 90% radioactive methyl iodide removal when tested in accordance with ASTM D3803-1989 (30 0 C, 95% RH), respectively.

d. Demonstrate, for the CRVS Booster Fan Trains, that the pressure drop across the pre-filter is < 1 in. of water and the pressure drop across the HEPA filters is

2 in. of water at the system design flow rate +/- 10%.

e. Demonstrate, for the SFPVS, that a dioctyl phthalate (DOP) test of the high efficiency particulate air (HEPA) filters shows > 99% removal when tested in accordance with ANSI N510-1975 at the system design flow rate

+/- 10%.

f. Demonstrate, for the SFPVS, that a halogenated hydrocarbon test of the carbon adsorber shows >_99% removal when tested in accordance with ANSI N510-1975 at the system design flow rate +/- 10%.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the VFTP test frequencies.

5.5.13 Explosive Gas and Storage Tank Radioactivity Monitorinq Pro-gram This program provides controls for potentially explosive gas mixtures contained in the waste gas holdup tanks and the quantity of radioactivity contained in waste gas holdup tanks, and the quantity of radioactivity contained in unprotected outdoor liquid storage tanks. The gaseous radioactivity quantities shall be determined. The liquid radwaste quantities shall be determined by analyzing a representative sample of the tank's contents at least once per 7 days when radioactive materials are being added to the tank.

OCONEE UNITS 1, 2, & 3 5.0-17 Amendment Nos. 355,357,& 356'

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.13 Explosive Gas and Storage Tank Radioactivity Monitoring Procqram (continued)

The program shall include:

a. The limit for concentration of hydrogen in the waste gas holdup tanks and a surveillance program to ensure the limit is maintained. The limit 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 waste gas holdup tank is less than the amount that would result in a whole body exposure of > 0.5 rem to any individual at the nearest exclusion area boundary, in the event of an uncontrolled release of the tank's contents.

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

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.

5.5.14 Standby Shutdown Facility (SSF) Diesel Fuel Oil Testing Program A diesel fuel oil testing program to implement required testing of SSF 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 acceptability of Day Tank and Underground Storage Tank fuel oil for use by determining that the fuel oil viscosity, water and sediment are within limits.

5.5.15 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.

OCONEE UNITS 1, 2, & 3 5.0-18 Amendment Nos. 355,357,& 356 I

Programs and Manuals 5.5 5,5 Programs and Manuals 5,5.15 Technical Specifications (TS) Bases Control Program (continued)

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

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

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

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 5.5.15.b.1 or 5.5.15.b.2 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).

5.5.16 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 limitations and remedial or compensatory actions may be identified to 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 safety 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.

OCONEE UNITS 1, 2, & 3 5.0-19 Amendment Nos. 355,357,& 356 1

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.16 Safety Function Determination Program (SFDP) (continued)

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.

5.5.17 Backup Method for Determining Subcooling Margin This program ensures the capability to accurately monitor the Reactor Coolant System Subcooling Margin. The program shall include the following:

a. Training of personnel, and

b. Procedures for monitoring.

5.5.18 KHU Commercial Power Generation Testinq Program The KHU Commercial Power Generation Testing Program shall include the following and shall be met during periods of KHU commercial power generation:

a. Verify upon an actual or simulated actuation signal, each KHU's overhead tie breaker and underground tie breaker actuate to the correct position from an initial condition of commercial power generation every 18 months.

b. Verify upon an actual or simulated actuation signal, each KHU's frequency is < 66 Hz in < 23 seconds from an initial condition of commercial power generation every 18 months.

OCONEE UNITS 1, 2, & 3 5.0-20 Amendment Nos. 355,357,& 356 1

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.18 KHU Commercial Power Generation Testing Program (continued)

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the KHU Commercial Power Generation Testing Program surveillance frequencies.

5.5.,19 Lee Combustion Turbine Testing Program The Lee Combustion Turbine (LCT) Testing program shall include the following and shall be met when a LCT is used to comply with Required Actions of Specification 3.8.1, "AC Sources-Operating" or as a emergency power source as allowed by LCO 3.8.2, "AC Sources-Shutdown":

a. Verify an LCT can energize both standby buses using 100kV line electrically separated from system grid and offsite loads every 12 months.

b. Verify an LCT can supply equivalent of one Unit's Loss of Coolant Accident (LOCA) loads plus two Unit's Loss of Off site Power (LOOP) loads when connected to system grid every 12 months.

c. Verify an LCT can provide equivalent of one Unit's LOCA loads within one hour through 100kV line electrically separated from system grid and offsite loads every 18 months.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Lee Combustion Turbine Testing Program surveillance frequencies.

5.5.20 Battery Discharge Testing Program The Battery Discharge Testing Program shall include the following and shall be met for batteries used to comply with LCO 3.8.3, "DC Sources Operating."

a. Verify battery capacity is _>80% of the manufacturer's rating when subjected to a performance discharge test or a modified performance discharge test once every 60 months. This frequency shall be reduced to 12 months when battery shows degradation, or has reached 90% of the expected life with capacity < 100% of manufacturer's rating, and 24 months when battery has reached 90% of the expected life with capacity

> 100% of manufacturer's rating.

OCONE.E UNITS 1, 2, & 3 5.0-21 Amendment Nos. 355,357,& 356 I

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.20 Battery Discharge Testing Program (continued)

b. If battery capacity is determined to be < 80% of the manufacturer's rating an OPERABILITY evaluation shall be initiated immediately and completed within the guidelines of the Oconee OPERABILITY program. If the OPERABILITY evaluation determines the battery OPERABLE, battery capacity shall be restored to > 80% of the manufacturer's rating within a time frame commensurate with the safety significance of the issue.

Otherwise, the battery shall be declared inoperable and the applicable Condition of Specification 3.8.3 shall be entered.

The provisions of SR 3.0.2 and SR 3.0.3 are applicable to the Battery Discharge Testing Program surveillance frequencies.

OCONEE UNITS 1, 2, & 3 5.0-22 Amendment Nos. 355,357,& 356 I

Reporting Requirements 5.6 5.0 ADMINISTRATIVE CONTROLS 5.6 Reporting Requirements The following reports shall be submitted in accordance with 10 CFR 50.4.

5.6.1 Deleted 5.6.2 Annual Radiological Environmental Operating Report

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

A single submittal may be made for a multiple unit station. The submittal should combine sections common to all units at the station.

The Annual Radiological Environmental Operating Report covering the operation of the unit during the previous calendar year shall be submitted by May 15 of each year.

The report shall include summaries, interpretations, and analyses of trends of the results of the radiological environmental monitoring program for the reporting period. The material provided shall be consistent with the objectives outlined in the Offsite Dose Calculation Manual (ODCM), and in 10 CFR 50, Appendix I, Sections IV.B.2, IV.B.3, and IV.C.

OCONEE UNITS 1, 2, & 3 5.0-23 Amendment Nos. 355,357,& 356 1

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.3 Radioactive Effluent Release Report

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

A single submittal may be made for a multiple unit station. The submittal should combine sections common to all units at the station; however, for units with separate radwaste systems, the submittal shall specify the releases of radioactive material from each unit.

The Radioactive Effluent Release Report covering the operation of the unit in the previous year shall be submitted prior to May 1 of each year in accordance with 10 CFR 50.36a. The report shall include a summary of the quantities of radioactive liquid and gaseous effluents and solid waste released from the unit.

The material provided shall be consistent with the objectives outlined in the ODCM and Process Control Program and in conformance with 10 CFR 50.36a and 10 CFR part 50, Appendix I,Section IV.B.1.

5,6.4 Deleted 5,6.5 CORE OPERATING LIMITS REPORT (COLR)

Core operating limits shall be established, determined and issued in accordance with the following:

a. Core operating limits shall be established prior to each reload cycle, or prior to any remaining portion of a reload cycle, and shall be documented in the COLR for the following:

1. Shutdown Margin limit for Specification 3.1.1;

2. Moderator Temperature Coefficient limit for Specification 3.1.3;

3. Physical Position, Sequence and Overlap limits for Specification 3.2.1 Rod Insertion Limits;

4. AXIAL POWER IMBALANCE operating limits for Specification 3.2.2;

5. QUADRANT POWER TILT (QPT) limits for Specification 3.2.3; OCONEE UNITS 1, 2, & 3 5.0-24 Amendment Nos. 355,357,& 356 1

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

6. Nuclear Overpower Flux/Flow/Imbalance and RCS Variable Low Pressure allowable value limits for Specification 3.3.1;

7. RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits for Specification 3.4.1

8. Core Flood Tanks Boron concentration limits for Specification 3.5.1;

9. Borated Water Storage Tank Boron concentration limits for Specification 3.5.4;

10. Spent Fuel Pool Boron concentration limits for Specification 3.7.12;

11. RCS and Transfer Canal boron concentration limits for Specification 3.9.1; and

12. AXIAL POWER IMBALANCE protective limits and RCS Variable Low Pressure protective limits for Specification 2.1.1.

b. The analytical methods used to determine the core operating limits shall be those previously reviewed and approved by the NRC, specifically those described in the following documents:

(1) DPC-NE-1002-A, Reload Design Methodology II; (2) NFS-1001-A, Reload Design Methodology; (3) DPC-NE-2003-P-A, Oconee Nuclear Station Core Thermal Hydraulic Methodology Using VIPRE-01; (4) DPC-NE-1004-A, Nuclear Design Methodology Using CASMO-3/SIMULATE-3P; (5) DPC-NE-2008-P-A, Fuel Mechanical Reload Analysis Methodology Using TACO3; (6) BAW-1 0192-P-A, BWNT LOCA - BWNT Loss of Coolant Accident Evaluation Model for Once-Through Steam Generator Plants; OCONEE UNITS 1, 2, & 3 5.0-25 Amendment Nos. 355,357,& 356 I

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

(7) DPC-NE-3000-P-A, Thermal Hydraulic Transient Analysis Methodology; (8) DPC-NE-2005-P-A, Thermal Hydraulic Statistical Core Design Methodology; (9) DPC-NE-3005-P-A, UFSAR Chapter 15 Transient Analysis Methodology; and (10) BAW-10227-P-A, Evaluation of Advanced Cladding and Structural Material (M5) in PWR Reactor Fuel.

The COLR will contain the complete identification for each of the Technical Specifications referenced topical reports used to prepare the COLR (i.e., report number, title, revision number, report date or NRC SER date, and any supplements).

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 System (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 Post Accident Monitoring (PAM) and Main Feeder Bus Monitor Panel (MFPMP)

Report When a report is required by Condition B or G of LCO 3.3.8, "Post Accident Monitoring (PAM) Instrumentation" or Condition D of LCO 3.3.23, "Main Feeder Bus Monitor Panel," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring (PAM only),

the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the Function to OPERABLE status.

5.6.7 Tendon Surveillance Report Any abnormal degradation of the containment structure detected during the tests required by the Pre-stressed 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.

OCONEE UNITS 1, 2, & 3 5.0-26 Amendment Nos. 355,357,& 356 1

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.8 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 Specification 5.5.10, 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.

OCONEE UNITS 1, 2, & 3 5.0-27 Amendment Nos. 355,357,& 356 1

RCS Loops - MODE 3 B 3.4.5 BASES (continued)

LCO The purpose of this LCO is to require two loops to be available for heat removal thus providing redundancy. The LCO requires the two loops to be OPERABLE with the intent of requiring both SGs to be capable of transferring heat from the reactor coolant at a controlled rate. Forced reactor coolant flow is the required way to transport heat, although natural circulation flow provides adequate removal. A minimum of one running RCP meets the LCO requirement for one loop in operation.

The Note permits a limited period of operation without RCPs. All RCPs may not be in operation for < 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months per 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period for the transition to or from the Decay Heat Removal (DHR) System, and otherwise may be de-energized for <1 hour per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. This means that natural circulation has been established. When in natural circulation, boron reduction is prohibited because an even concentration distribution throughout the RCS cannot be ensured. Core outlet temperature is to be maintained at least 1 0°F below the saturation temperature so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

In MODES 3,4, and 5, it is sometimes necessary to stop all RCP or LPI pump forced circulation (e.g., change operation from one DHR loop to the other, to perform surveillance or startup testing, to perform the transition to and from DHR mode cooling, or to avoid operation below the RCP minimum net positive suction head limit). This is acceptable because natural circulation is adequate for heat removal, or the reactor coolant temperature can be maintained subcooled and boron stratification affecting reactivity control is not expected.

An OPERABLE RCS loop consists of at least one OPERABLE RCP and an SG that is OPERABLE. An RCP is OPERABLE if it is capable of being powered and is able to provide forced flow if required.

APPLICABILITY In MODE 3, the heat load is lower than at power; therefore, one RCS loop in operation is adequate for transport and heat removal. A second RCS loop is required to be OPERABLE but not in operation for redundant heat removal capability.

OCONEE UNITS 1, 2, & 3 B 3.4.5-2 Amendment Nos. 355,357,& 356 1

RCS Loops - MODE 4 B 3.4.6 BASES LCO so that no vapor bubble may form and possibly cause a natural circulation (continued) flow obstruction.

Note 1 also permits the DHR pumps to be stopped for _<1 hour per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. When the DHR pumps are stopped, no alternate heat removal path exists, unless the RCS and SGs have been placed in service in forced or natural circulation. The response of the RCS without the DHR loop depends on the core decay heat load and the length of time that the DHR pumps are stopped. As decay heat diminishes, the effects on RCS temperature and pressure diminish. Without cooling by DHR, higher heat loads will cause the reactor coolant temperature and pressure to increase at a rate proportional to the decay heat load. Because pressure can increase, the applicable system pressure limits (pressure and temperature (P/T) or low temperature overpressure protection (LTOP) limits) must be observed and forced DHR flow or heat removal via the SGs must be re-established prior to reaching the pressure limit. The circumstances for stopping both DHR trains are to be limited to situations where:

a. Pressure and temperature increases can be maintained well within the allowable pressure (P/T and LTOP) and 10°F subcooling limits; or

b. An alternate heat removal path through the SG is in operation.

Note 2 allows a DHR loop to be considered OPERABLE if it is capable of being manually (locally or remotely) realigned to the DHR mode of operation and is not otherwise inoperable. This provision is necessary because of the dual function of the components that comprise the decay heat removal mode of the Low Pressure Injection System.

An OPERABLE RCS loop consists of at least one OPERABLE RCP and an SG that is OPERABLE.

Similarly for the DHR loops, an OPERABLE DHR loop is comprised of the OPERABLE LPI pump(s) capable of providing forced flow to the LPI heat exchanger(s). LPI pumps are OPERABLE if they are capable of being powered and are able to provide 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.

OCONEE UNITS 1, 2, & 3 B 3.4.6-2 Amendment Nos. 355,357,& 356 1

RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO Note 2 allows one required DHR loop to be inoperable for a period of (continued) < 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided that the other 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 provides for an orderly transition from MODE 5 to MODE 4 during a planned heatup by permitting DHR loops to not be in operation when at least one RCP is in operation. This Note provides for the transition to MODE 4 where an RCP is permitted to be in operation and replaces the RCS circulation function provided by the DHR loops.

Note 4 allows a DHR loop to be considered OPERABLE during alignment and when aligned for low pressure injection if it is capable of being manually (locally or remotely) realigned to the DHR mode of operation and is not otherwise inoperable. This provision is necessary because of the dual requirements of the components that comprise the low pressure injection/decay heat removal system.

To be considered OPERABLE, a DHR loop must consist of a pump, a heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path and to determine the temperature. The flow path starts in one of the RCS hot legs and is returned to reactor vessel via one or both Core Flood tank injection nozzles. The BWST recirculation crossover line through valves LP-40 and LP-41 may be part of a flow path if it provides adequate decay heat removal capability. The operability of the operating DHR loop and the supporting heat sink is dependent on the ability to maintain the desired RCS temperature. LPSW and ECCW are required to support the OPERABLE DHR train(s). One LPSW pump and one ECCW header can simultaneously support one or two DHR trains.

Single failure protection is not required for LPSW or support systems in these modes.

To be considered OPERABLE, DHR loops must be capable of being powered and are able to provide flow if required. An SG can perform as a heat sink when it has an adequate water level and is OPERABLE.

APPLICABILITY In MODE 5 with loops filled, forced circulation is provided by this LCO to remove decay heat from the core and to provide proper boron mixing. One loop of DHR in operation provides sufficient circulation for these purposes.

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";

OCONEE UNITS 1, 2, & 3 B 3.4.7-3 Amendment Nos. 355,357,& 356 I

RCS Operational LEAKAGE B 3.4.13 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.13 RCS Operational LEAKAGE BASES BACKGROUND Components that contain or transport the coolant to or from the reactor core make up the RCS. Component joints are made by welding, bolting, rolling, or pressure loading, and valves isolate connecting systems from the RCS.

During unit life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. The purpose of the RCS Operational LEAKAGE LCO is to limit system operation in the presence of LEAKAGE from these sources to amounts that do not compromise safety. This LCO specifies the types and amounts of LEAKAGE.

The safety significance of RCS LEAKAGE varies widely depending on its source, rate, and duration. Therefore, detecting and monitoring reactor coolant LEAKAGE into the containment area is necessary. Separating the identified LEAKAGE from the unidentified LEAKAGE is necessary to provide quantitative information to the operators, allowing them to take corrective action should a leak occur detrimental to the safety of the facility and the public.

This LCO deals with protection of the reactor coolant pressure boundary (RCPB) from degradation and the core from inadequate cooling, in addition to preventing the accident analysis radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident (LOCA). However, the ability to monitor leakage provides advance warning to permit unit shutdown before a LOCA occurs. This advantage has been shown by "leak before break" studies.

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 steam line break (SLB) analysis assumes total primaryto secondary LEA.KAGE of 150 gallons per day per SG as the initial condition.

.1 OCONEE UNITS 1, 2, & 3 B 3.4.13-1 Amendment Nos. 355,357,& 356

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Primary to secondary LEAKAGE is a factor in the dose releases outside SAFETY ANALYSES containment resulting from a SLB accident. To a lesser extent, other (continued) accidents or transients involve secondary steam release to the atmosphere, such as a steam generator tube rupture (SGTR). The leakage contaminates the secondary fluid and can be released to the environment.

The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is less than the conditions assumed in the safety analyses. The dose consequences resulting from the SLB accident are within the limits defined in 10 CFR 100.

RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36 (Ref.3).

LCO RCS LEAKAGE includes leakage from connected systems up to and including the second normally closed valve for systems which do not penetrate containment and the outermost isolation valve for systems which penetrate containment. Loss of reactor coolant through reactor coolant pump seals and system valves to connecting systems which vent to the gas vent header and from which coolant can be returned to the RCS shall not be considered as RCS LEAKAGE.

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, gaskets, and steam generator tubes 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.

OCONEE UNITS 1, 2, & 3 B 3.4.13-2 CAmendment Nos. 355,357,& 356 I

RCS Operational LEAKAGE B 3.4.13 BASES LCO c. Identified LEAKAGE (continued)

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

OCONEE UNITS 1, 2, & 3 B 3.4.13-3 Amendment Nos. 355,357,& 356 I

RCS Operational LEAKAGE B 3.4.13 BASES (continued)

ACTIONS A.1 If unidentified LEAKAGE or identified LEAKAGE are in excess of the LCO limits, the LEAKAGE must be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . 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, identified, or primary to secondary LEAKAGE cannot be reduced to within limits within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. The reactor must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

The Completion Times allowed are reasonable, based on operating experience, to reach the required conditions 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 Evaluation of RCS LEAKAGE ensures identified and unidentified leakage is maintained within the associated LCO limits and ensures that the integrity of the RCPB is maintained. Identified and unidentified LEAKAGE is determined by performance of an RCS water inventory balance. This method provides the required leakage detection sensitivity to ensure leakage is within limits.

The RCS water inventory balance must be performed with the reactor at steady state operating conditions and near operating pressure. The surveillance is modified by two Notes. Note 1 states that this SR is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. This 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance provides sufficient time to collect and process all necessary data after stable plant conditions are established.

OCONEE UNITS 1, 2, & 3 B 3.4.13-4 Amendment Nos. 355,357,& 356 1

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

REQUIREMENTS Steady state operation is required to perform a proper water 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 pump seal injection and return flows.

An early warning of LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level.

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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 this LCO, as well as LCO 3.4.16, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Ref. 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 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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.

OCONEE UNITS 1, 2, & 3 B 3.4.13-5 Amendment Nos. 355,357,& 356 1

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.2 (continued)

REQUIREMENTS The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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).

REFERENCES 1. UFSAR, Section 3.1.

2. UFSAR, Chapter 15.

3. 10 CFR 50.36.

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

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

OCONEE UNITS 1, 2, & 3 B-3.4,13-6 Amendment Nos. 355,357,&'356 I

SG Tube Integrity B 3.4.16 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.16 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. Steam generator 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.

Steam generator tubing is subject to a variety of degradation mechanisms. Steam generator 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 5.5.10, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.10, 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 5.5.10. Meeting the SG performance criteria provides reasonable assurance of 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).

OCONEE UNITS 1, 2, & 3 B 3.4.16-1 Amendment Nos. 355,357,& 3561

SG Tube Integrity B 3.4.16 BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES Specification. The analysis of a SGTR event assumes a bounding primary to secondary LEAKAGE rate equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE," plus the leakage rate associated with a double-ended rupture of a single tube. The accident analysis for a SGTR assumes cooldown via the main steam atmosphere dump valves.

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 bounds the primary to secondary LEAKAGE of 150 gallons per day per SG. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16, "RCS Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3) or the NRC approved licensing basis (e.g., a small fraction of these limits).

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

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

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

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 5.5.10, "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.

OCONEE UNITS 1, 2,,& 3 B 3.4.16-2 Amendment Nos. 355,357,& 3561

SG Tube Integrity, B 34.16 BASES LCO (continued) 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. Thecondition 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 Usignificant" is defined as "An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of the 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 includ6d in the design specification.

This includes safety factors and applicable design basis loads based on ASME Code,Section III, Subsection NB (Ref. 4) and Draft Regulatory Guide 1.121 (Ref. 5).

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The accident analysia assumes that accident induced leakage does not exceed 150 gallons per day per SG. 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.

OCONEE UNITS 1, 2, & 3 B 3.4.16-3 Amendment Nos. 355,357,& 356 I

SG Tube Integrity B 3.4.16 1 BASES LCO (continued) 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 Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

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

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

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube repair criteria but were not plugged in accordance with the Steam Generator Program as required by SR 3.4.16.2. 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, which ever is shorter. 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.

OCONEE UNITS 1, 2, & 3 B 3.4.16-4 Amendment Nos. 355,357,& 356 I

SG Tube Integrity B 3.4.16 BASES ACTIONS A.1 and A.2 (continued)

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

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

This Completion Time is acceptable since operation until the next inspection is supported by the operational assessment.

B.1 and B.2 If the Required Actions and associated Completion Times of Condition A are not met or if SG tube integrity is not being maintained, the reactor must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

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 3.4.16.1 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.

OCONEE UNITS 1, 2, & 3 B 3.4.16-5 Amendment Nos. 355,357,& 356 1

SG Tube Integrity B 3.4.16 BASES SURVEILLANCE SR 3.4.16.1 (continued)

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

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

The Steam Generator Program defines the Frequency of SR 3.4.16.1.

The Frequency is determined by the operational assessment and other limits in the SG examination guidelines (Ref. 6). The Steam Generator Program uses information on existing degradations and growth rates to determine an inspection Frequency that provides reasonable assurance that the tubing will meet the SG performance criteria at the next scheduled inspection. In addition, Specification 5.5.10 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.16.2 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 5.5.10 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 irepair criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.

OCONEE UNITS 1, 2, & 3 B 3.4.16-6 Amendment Nos. 355,357,& 356 I

SG Tube Integrity B 3.4.16 BASES REFERENCES 1. NEI 97-06, "Steam Generator Program Guidelines."

2. 10 CFR 50 Appendix A, GDC 19.

3. 10CFR100.

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

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

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

OCONEE UNITS 1, 2, & 3 B, 3.4.16-7 Amendment Nos. 355,357,& 356 I

v t e Letter Sequence Approval
TAC:MD2038, Steam Generator Tube Integrity (Approved, Closed) TAC:MD2039, Steam Generator Tube Integrity (Approved, Closed) TAC:MD2040, Steam Generator Tube Integrity (Approved, Closed) TAC:MD2043, Steam Generator Tube Integrity (Approved, Closed) TAC:MD2044, Steam Generator Tube Integrity (Approved, Closed) TAC:MD2045, Steam Generator Tube Integrity (Approved, Closed)
Initiation Acceptance... Administration Questions Answers 24 October 2006 Results Approval, Approval Other:
MONTHYEAR2006-10-24 [Table View]

ML070930372

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