ML042660280

Proposed Technical Specifications (TS) Amendments Revision to Steam Generator TS

ML042660280
Person / Time
Site:	Catawba
Issue date:	09/13/2004
From:	Jamil D Duke Power Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC MB7842, TAC MB7843
Download: ML042660280 (45)

Text

Duke D.M. JAMIL rfPower. Vice President A Duke Energy Company Duke Power Catawba Nuclear Station 4800 Concord Rd. / CN01 VP York, SC 29745-9635 803 831 4251 803 831 3221 fax September 13, 2004 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555

Subject:

Duke Energy Corporation Catawba Nuclear Station, Units 1 and 2 Docket Numbers 50-413 and 50-414 Proposed Technical Specifications (TS) Amendments Revision to Steam Generator TS TAC Nos. MB7842 and MB7843

References:

Letters from Duke Energy Corporation to NRC, dated February 25, 2003, June 9, 2003, and July 30, 2003 The reference letters collectively constitute Duke Energy Corporation's submittal to date in response to the industry initiative known as the NEI Generic License Change Package (GLCP).

On May 14, 2004, representatives of the industry and NRC met to discuss the remaining unresolved technical issues associated with the GLCP. The most significant of these involved the wording of the Structural Integrity Performance Criterion (SIPC) and the results of the SIPC impact study conducted by the industry. The SIPC is being written into TS 5.5.9, Steam Generator (SG) Program. The second issue involved the definitions of tube "collapse" and "significant", which are being included in the new TS Bases B 3.4.18, Steam Generator (SG) Tube Integrity. The third issue involved the treatment of thermal loads. This letter constitutes Duke Energy Corporation's submittal of the revised license amendment request documentation as agreed to following the May 14, 2004 meeting.

As agreed upon between the industry and NRC, the final wording of the SIPC is as follows:

www. dukepower. corn

Document Control Desk Page 2 September 13, 2004 "All inservice SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cooldown, and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 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."

In addition to the safety factors of 3.0 and 1.4, the SIPC requires further adjustments to ensure representative verification of tube integrity for various damage forms.

The assessment of these additional conditions as defined in the design and licensing basis, assures that other loading conditions that can significantly contribute to tube burst or collapse are addressed. Such loads include loads associated with locked tube supports which could be postulated to develop in recirculating SG designs. The inclusion of these loads, when determined to affect tube burst or collapse conditions, shall have a safety factor as specified in the SIPC applied to the appropriate load value.

The definitions of "collapse" and "significant are as follows:

"Collapse - 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.

"Significant - An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of structural integrity performance criterion causes a lower structural

Document Control Desk Page 3 September 13, 2004 limit or limiting burst/collapse condition to be established."

Regarding the treatment of axial secondary loads, thermal loads will be evaluated as follows:

• For tube integrity evaluations, except for circumferential degradation, axial thermal loads are classified as secondary.

• For circumferential degradation, the classification of axial thermal loads as primary or secondary 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.

As previously indicated by the industry, the discussion concerning the treatment of thermal loads will be documented in an industry white paper on the subject.

Some of the marked-up TS and Bases pages transmitted to the NRC via the reference letters have been superceded since their transmittal. Accordingly, the attachment to this letter contains all of the marked-up TS and Bases pages for all TS and Bases sections impacted by the GLCP. The marked-up pages are being resubmitted in their entirety for ease of NRC review. The corresponding reprinted TS and Bases pages will be provided to the NRC Project Manager when the NRC is ready to approve this amendment request package.

Duke Energy Corporation has concluded that the original No Significant Hazards Consideration Analysis and Environmental Analysis associated with these amendment requests continue to remain valid as a result of this supplemental submittal.

Pursuant to 10 CFR 50.91, a copy of this letter is being sent to the appropriate State of South Carolina official.

Inquiries on this matter should be directed to L.J. Rudy at (803) 831-3084.

Very truly yours, Dhiaa M. Jamil Attachment

Document Control Desk Page 4 September 13, 2004 Dhiaa M. Jamil affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.

c Subscribed and sworn to me: ~to . 153Ietz4n

&P Date Notary Public tloay PURe, South Carolina, Sto% at targL My commission expires: 1it Commission Expires March 6, 2008 Date S EAv

Document Control Desk Page 5 September 13, 2004 xc (with attachment):

W.D. Travers U.S. Nuclear Regulatory Commission Regional Administrator, Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, GA 30303 E.F. Guthrie Senior Resident Inspector (CNS)

U.S. Nuclear Regulatory Commission Catawba Nuclear Station L.N. Olshan (addressee only)

NRC Senior Project Manager U.S. Nuclear Regulatory Commission Mail Stop 0-8 H12 Washington, D.C. 20555-0001 H.J. Porter, Assistant Director Division of Radioactive Waste Management Bureau of Land and Waste Management Department of Health and Environmental Control 2600 Bull St.

Columbia, SC 29201

ATTACHMENT Revised Marked-Up TS and Bases Pages for GLCP

TABLE OF CONTENTS (continued) 3.4 REACTOR COOLANT SYSTEM (RCS) .............................................. 3..1-1 4 3.4.1 RCS Pressure, Temperature, and Flow Departure from Nucleate Boiling (DNB) Limits .............................................. 3A.1-1 3.4.2 RCS Minimum Temperature for Criticality....................................... 3.4.2-1 3.4.3 RCS Pressure and Temperature (PIT) limits ................................. 3.4.3-1 3.4.4 RCS Loops - MODES 1 and 2......................................................3A.-1 3.4.5 RCS Loops-MODE 3.............................................. 3.4.5-1 3.4.6 RCS Loops-MODE 4 .............................................. 3.4.6-1 3.4.7 RCS Loops - MODE 5, Loops Filled .............................................. 3.4.7-1 3.4.8 RCS Loops - MODE 5, Loops Not Filled ....................................... 3.4.8-1 3.4.9 Pressurizer .............................................. 3.4.9-1 3.4.10 Pressurizer Safety Valves...............................................................3A.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 (PIlV) 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 R SLo Test Exceptions .............................................. 3.4.17-1 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 3.6 CONTAINMENT SYSTEMS .............................................. 3.6.1-1 3.6.1 Containment .............................................. 3.6.1-1 3.6.2 Containment Air Locks ............... ............................... 3.6.2-1 3.6.3 Containment Isolation Valves .............................................. 3.6.3-1 3.6.4 Containment Pressure .............................................. 3.6.4-1 3.6.5 Containment Air Temperature ................................ .............. 3.6.5-1 3.6.6 Containment Spray System .............................................. 3.6.6-1 laCZ7 3.6..

Hydrogen Recombiners .............................................. 3.6.7-1 3.6.8 Hydrogen Skimmer System (HSS) .............................................. 3.6.8-1 3.6.0 Hydrogen Ignition System (HIS) .............................................. 3.6.9-1 3.6.10 Annulus Ventilation System (AVS) .............................................. 3.6.10-1 3.6.11 Air Return System (ARS) .............................................. 3.6.11-1 3.6.12 Ice Bed .............................................. 3.6.12-1 3.6.13 Ice Condenser Doors .............................................. 3.6.13-1 3.6.14 Divider Barrier Integrity.............................................. 3.6.14-1 3.6.1E Containment Recirculation Drains .............................................. 3.6.15-1 3.6.1E Reactor Building .............................................. 3.6.16-1 3.6.17 r Containment Valve Injection Water System (CVIWS) ............ ......... 3.6.17-1 1)

Hz dt OV\ C_". rcr'. r ( g& /,,+,e y .-f, S .'t. 0 - -

Catawba Units I and 2 ii Amendment NosshZD

TABLE OF CONTENTS B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.9 Pressurizer ....... B 3.4.9-1 B 3.4.10 Pressurizer Safety Valves .B 3.4.10-1 B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) .B 3.4.11-1 B 3.4.12 Low Temperature Overpressure Protection (LTOP) System . B 3.4.12-1 B 3.4.13 RCS Operational LEAKAGE .B 3.4.13-1 B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage .B 3.4.14-1 B 3.4.15 RCS Leakage Detection Instrumentation .B 3.4.15-1 B 3.4.16 RCS Specific Activity .B 3.4.16-1 B 3.4.17 RCS Loops-Test Exceptions.B 3.4.17-1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1 Accumulators .B 3.5.1-1 B 3.52 ECS-Operating .B 3.5.2-1 B 3.5.3 ECGS-Shutdown .B 3.5.3-1 B 3.5.4 Refueling Water Storage Tank (RWST) .B 3.5.4-1 B 3.5.5 Seal Injection Flow .B 3.5.5-1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1 Containment .B 3.6.1-1 B 3.6.2 Containment Air Locks .B 3.6.2-1 B 3.6.3 Containment Isolation Valves .B 3.6.3-1 B 3.6.4 Containment Pressure .B 3.6.4-1 B 3.6.5 Containment Air Temperature .B 3.6.5-1 B 3.6.6 Containment Spray System .B 3.6.6-1 B 3.6.7 Hydrogen Recombiners .B 3.6.7-1 B 3.6.8 Hydrogen Skimmer System (HSS) .B 3.6.8-1 B 3.6.9 Hydrogen Ignition System (HIS) .B 3.6.9-1 B 3.6.10 Annulus Ventilation System (AVS) .B 3.6.10-1 B3.6.11 Air Return System (ARS) .B 3.6.11-1 B 3.6.12 Ice Bed .B 3.6.12-1 B3.6.13 Ice Condenser Doors. B 3.6.13-1 B 3.6.14 Divider Barrier Integrity .B 3.6.14-1 B 3.6.15 Containment Recirculation Drains .B 3.6.15-1 B 3.6.16 Reactor Building ............ ...... B 3.6.16-1 B 3.6.17 Containment Valve Injection Water System (CVIWS) .B 3.6.17-1 B 3.7 PLANT SYSTEMS B 3.7.1 Main Steam Safety Valves (MSSVs) . B 3.7.1-1 .

B 3.7.2 Main Steam Isolation Valves (MSIVs) . B 3.7.2-1 .

B 3.7.3 Main Feedwater Isolation Valves (MFIVs), Mair i Feedwater Control Valves (MFGVs), their Associated Bypass Valves.

and the Tempering Valves. 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 Condensate Storage System (CSS). B 3.7.6-1 .

i .-,<I Catawba Units 1 and 2 ii Revision Nop/

RCS Loops - MODES 1 and 2 B 3.4.4 BASES APPLICABLE SAFETY ANALYSES (continued) assuming the number of RCS loops in operation is consistent with the Technical Specifications. The majority of the plant safety analyses are based on initial conditions at high core power or zero power. The primary coolant flowrate, and thus the number of RCPs in operation, is an important assumption In all accident analyses (Ref. 1).

Steady state DNB analysis has been performed for the four RCS loop operation. For four RCS loop operation, the steady state DNB analysis, which generates the pressure and temperature Safety Limit (SL) (i.e., the departure from nucleate boiling ratio (DNBR) limit) assumes a maximum power level of 118% RTP. This is the design overpower condition for four RCS loop operation. The DNBR limit defines a locus of pressure and temperature points that result in a minimum DNBR greater than or equal to the critical heat flux correlation limit.

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

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

LCO The purpose of this LCO is to require an adequate forced flow rate for core heat removal. Flow is represented by the number of RCPs in operation for removal of heat by the SGs. To meet safety analysis acceptance criteria for DNB, four pumps are required in MODES 1 and 2.

An OPERABLE RCS loop consists of an OPERABLE RCP in operation providing forced flow for heat transport and an OPERABLES cco ance with Me Steam Gen rator Tube S etlance Proeri APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to produce maximum THERMAL POWER. Thus, to ensure that the assumptions of the accident analyses remain valid, all RCS loops are required to be OPERABLE and in operation in these MODES to prevent DNB and core damage.

The decay heat production rate is much lower than the full power heat rate. As such, the forced circulation flow and heat sink requirements are reduced for lower, noncritical MODES as indicated by the LCOs for MODES 3, 4, and 5.

Operation in other MODES is covered by:

Catawba Units 1 and 2 B 3.4.4-2 Revision No-O }

RCS Loops - MODE 3 B 3.4.5 BASES LCO (continued)

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

a. No operations are permitted that would dilute the RCS boron concentration with coolant at boron concentration less than required to assure the SDM of LCO 3.1.1 and maintain ket < 0.99, thereby maintaining an adequate margin to criticality. Boron reduction with coolant at boron concentration less than required to assure SDM and maintain krff < 0.99, 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 100F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

An OPERABLE RCS Ioo consists of o ffE n d one OPERABL Sane/vtht tam Gene96tqrT eu,)

u ac Progra w as the minimum water level specified in hic SR 3.4.5. An is OPERABLE if it is capable of being powered and is able to provide forced flow if required.

APPLICABILITY In MODE 3, this LCO ensures forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mixing.

The most stringent condition of the LCO, that is, three RCS loops OPERABLE and three RCS loops in operation, applies to MODE 3 with RTBs in the closed position. The least stringent condition, that is, three RCS loops OPERABLE and one RCS loop in operation, applies to MODE 3 with the RTBs open.

Operation in other MODES is covered by:

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

LCO 3.4.6, 'RCS Loops-MODE 4; LCO 3.4.7, 'RCS Loops-MODE 5, Loops Filled";

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

LCO 3.4.17, ARCS Loops-Test Exceptions";

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

Catawba Units 1 and 2 B 3.4.5-3 Revision NoT

RCS Loops - MODE 4 B 3.4.6 BASES LCO (continued) performed during the startup testing program is the validation of rod drop times during cold conditions, both with and without flow. The no flow test may be performed In MODE 3, 4, or 5 and requires that the pumps be stopped for a short period of time. The Note permits the de-energizing of the pumps in order to perform this test and validate the assumed analysis

- values. If changes are made to the RCS that would cause a change to the flow characteristics of the RCS, the input values must be revaldated by conducting the test again. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> time period is adequate to perform the test, and operating experience has shown that boron

-stratification Is not a problem during this short period with no forced flow.

Utilization of Note 1 Is permitted provided the following conditions are met along with any other conditions imposed by initial startup test procedures:

a. No operations are permitted that would dilute the RCS boron concentration with coolant with boron concentrations less than required to meet SDM of LCO 3.1.1 and maintain keff < 0.99, therefore maintaining an adequate margin to criticality. Boron reduction with coolant at boron concentrations less than required to assure SDM and maintain kff < 0.99 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 100 F below saturation temperature, so that no vapor bubble may form and possibly cause a natural circulation flow obstruction.

Note 2 requires that the secondary side water temperature of each SG be

< 500 F above each of the RCS cold leg temperatures before the start of an ROP with any RCS cold leg temperature

• 21 0F. This restraint is to prevent a low temperature overpressure event due to a thermal transient when an RCP is started.

An OPERABLE RCS comprises an OPERABLE RCP and an OPERABLE SG~ acine team G e ineto-r~u~eD rvlanPogra has the minimum water levere specified in SR 3.4.62. e water level is maintained by an OPERABLE AFW train in accordance with LCO 3.7.5, Auxiliary Feedwater System.

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

Catawba Units 1 and 2 B 3A.6-2 Revision No(p

RCS Loops - MODE 5, Loops Filled B 3.4.7 BASES LCO (continued) reactor coolant pump (RCP) with an RCS cold leg temperature < 21 0OF.

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.

An OPERABLE RHR loop Is comprised of an OPERABLE RHR pump capable of providing forced flow to an OPERABLE RHR heat exchanger.

If not In its normal RHR alignment from the :RCS hot leg andreturning to the RCS cold legs, the required RHR loop is OPERABLE provided the system may be placed In service from the control room, or may be placed in service In a short period of time by actions outside the control room and there are no restraints to placing the equipment in service. RHR pumps are OPERABLE If they are capable of being powered and are able to provide flow If required. An OPERABLE SG can perform as a heat sink when it has an adequate wetter Ievpe4njd is QPERA4BLnacod t Qveep Geera uErveillancyPro APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation of the reactor coolant to remove decay heat from the core and to provide proper boron mbing. One loop of RHR provides sufficient circulation for these purposes. However, one additional RHR loop is required to be OPERABLE, or the secondary side narrow range water level of at least two SGs is required to be 2 12%h.

Operation in other MODES is covered by:

LCO 3AA, *RCS Loops-MODES 1 and 2-;

LCO 3A..5 'RCS Loops-MODE 3%;

LCO 3A.6, 'RCS Loops-MODE 4; LCO 3.4.8, *RCS Loops-MODE 5, Loops Not Filled';

LCO 3.4.17 'RCS Loops-Test Exceptions";

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

Catawba Units 1 and 2 B 3A.7-3 Revision Nos -

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

a. No pressure boundary LEAKAGE;

b. 1 gpm uinidentified LEAKAGE; C. 10 gpm identified LEAKAGE; g (d. A7 gealhns per o~

t _ genfatoa;(jigs)

Yern at );prmary to s7ndary LEAKa and //

)

150 gallons per day primary to secondary LEAKAGE through any 0-0 one0)__

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

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME 4- 4-A.  ;LRC EAKAGE not A-1 Reduce LEAKAGE to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> within limits for reasons within limits.

Of f6 t other than pressure boundary LEAKAGE.

I- ---

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion .

Time of Condition A not AND met.

8.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> OR Pressure boundary LEAKAGE exists.

r rtscy +o and 2 tawa UitsI and 2 3.4.13-1 Amendment Nos.Ey\

RCS Operational LEAKAGE 3.4.13 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.13.1 NNO -NOTE-( Not required to be performed until Only required to eill; 12 hou steady state operation. be performed during steady state operation S.7 otrJa4Ie~+ pre~e -* ^L S~R~r9 kA Verify RCS Operational LEAKAGE within limits by 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> performance of RCS water inventory balance.

SR 3.4.13.2 erify sam generat r tube integritis in accor ance n acrdance ith with t Steam Gen ator Tube Su) eillance P gram. the team G nrator TD OTC' -

/ \/Otreci~Quo.Q .foStperI~r'~'LivdKI vr \ (0d 1 rVreJ-}sok \-

c;ffo-CA

.s1+l.'ikc,+ of soP'i

_Se p St

<_~}S open+eA. / Fe~.ee c~vr.^

ve ( Cuf eco irw L -A;t7_ .so+V Itt~

fi 51 fIoIs- p iex _a 44'°oJj at41 Q SIG. 7;_ IaoqjtJ Catawba Units I and 2 3.4.1 3-2 Amendment Nos.6Ez

K0 CHARGES TlHS PAGE. RCS Operational LEAKAGE FOR IlFORATATIOR olity 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 oading._andevalves isolate connecting systems from the RCS.

During plant 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.

10 CFR 50, Appendix A, GDC 30 (Ref. 1). requires means for detecting and, to the extent practical, Identifying the source of reactor coolant LEAKAGE. Regulatory Guide 1.45 (Ref. 2) descrfbes acceptable methods for selecting leakage detection systems.

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. Quickly 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 that is detrimental to the safety of the facility and the public.

A limited amount of leakage inside containment is expected from auxiliary systems that cannot be made 100%h leaktight- Leakage from these systems should be detected, located, and isolated from the containment atmosphere, if possible, to not interfere with RCS leakage detection.

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 analyses radiation release assumptions from being exceeded. The consequences of violating this LCO indude the possibility of a loss of coolant accident (LOCA).

APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses do not SAFETY ANALYSES 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.

Catawba Units 1 and 2 B 3.4.13-1 Revision No. 0

RCS Operational LEAKAGE B 3A.13 BASES APPUCABLE SAFETY ANALYSES (continued)

The safety analysis (Ref. 3 foern event resulti in steam di e to atmosphere assumes 576fpd primary ta lea e as the

_ii n(i*dt 5 e ~-~-y event in whiich the reactor coolant system will continue to leak water inventory to the secondary side, and in which there Will be a postulated source term associated with the accident, utilizes this leakage value as an Input in the analysis. These accidents include the rod ejection accident, locked rotor accident, main steam line break steam generator tube rupture and unconltrolled rod withdrawal accident The rod ejection accident, locked rotor accident and uncontrolled rod withdrawal accident yield a source term due to postulated fuel failure as a result of the accident The main steam line break and the steam generator tube rupture yield a source term due to perforations in fuel pins causing an iodine spike. Primary to secondary side leakage may escape the secondary side due to flashing or atomization of the coolant, or it may mix with the secondary side SG water inventory and be released due to steaming of the SGs. The rod ejection accident is limiting compared to the remainder of the accidents with respect to dose results. The dose results for each of the accidents delineated above are well within 10 CFR 100 limits for the rod ejection accident, and below a small fraction of 10 CFR 100 limits for the remainder of the accidents.

The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36 (Ref. 4).

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 Catawba Units 1 and 2 B 3.4.13-2 Revision No-O) I

INSERT A for B 3.4.13 Applicable Safety Analyses:

that primary to secondary LEAKAGE from each steam generator (SG) is 150 gallons per day

RCS Operational LEAKAGE B 3A.13 BASES LO0 (continued) can detect within a reasonable time period. Violation of this Lo 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 or totaLLEAKAGE and is well within the capabilitfyotthe RCS Makeup System. Identified LEAKAGE includes LEAKAGE captured by the pressurizer refief tank and reactor coolant drain tank, as well as quantified 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. P rv to Secondar /AKAGE through A/Steam Generats otal primary to s ndary LEAKAGE a ounting to 576 9 through all SGs pr duces acceptable opsite doses in the ccident analysis. Violatio of this LCO could ceed the offsite d se limits for the previousl described accident Primary to secoo ary LEAKAGE mu be included in the t tat allowable limit f r identified I EAKAGE.

( D ) Primary to Secondary LEAKAGE through Any One SG

_ sUrpi that a single ctckleaking this am nt would not Q prpagae t a STR nf r the stress conditin of a OAoa maifstam inerupurelfleaked fthough poycracks, tcak sarhey rnalan thpbveassumption consenaie APPLICABILITY In MODES 1, 2,3, and i,.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.

Catawba Units 1 and 2 B 3.4-13-3 PRevision No.0 /

INSERT B for B 3.4.13 LCO:

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. 6).

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 primary to secondary LEAKAGE measurement is based on the methodology described in Ref. 5. Currently, a correction factor is applied to account for the fact that current safety analyses take the primary to secondary leak rate at reactor coolant conditions, rather than at room temperature as described in Ref. 5.

The operational LEAKAGE rate limit applies to LEAKAGE in any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the LEAKAGE should be conservatively assumed to be from one SG.

The limit in this criterion is based on operating experience gained from SG tube degradation mechanisms that result in tube LEAKAGE. The operational LEAKAGE rate criterion in conjunction with implementation of the Steam Generator Program is an effective measure for minimizing the frequency of SG tube ruptures.

RCS Operational LEAKAGE B3.4.13 BASES APPLICABILITY (continued)

LCO 3.4.14, *RCS Pressure Isolation Valve (PIV) Leakage. measures leakage through each Indivdual PIV and can Impact this LCO. -Of the two PlVs 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 unidentified LEAKAGE.

-ACTIONS A.1 Unidentified LEAKAGE4dentifed LEAKAG Go-ja6se ray 3in excess oe LCO imits must be reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 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.

or t Y V 4ZfCGEry D-A"Gg- ;r B.1 and B.2 Ibu /Iin.

};h ;*J1 If any pressure bounda LEAKAGE ezdsts or if unidentified LEAKAGldJ) identified LEAKAGI or ninar second LEAK Eannot be (

reduced to within limits within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. the reactor must be brought to lower pressure conditions to reduce the severity of the LEAKAGE and its potential consequences. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. The reactor must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This action reduces the LEAKAGE and also reduces the factors that tend to degrade the pressure boundary.

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an ordedy manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

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 Catawba Units 1 and 2 B 3.4.13-4 Revision WAd I

RCS Operational LEAKAGE 83.4.13 BASES I (

SURVEILLANCE REQUIREMENTS (dontinued)

LEAKAGE are detei b pened rfomiance of an RCS -ater Inventory baaoeJ^ to Noondary IAAqsalso measurel

{penoanoeof an RMqwatar In~v~entlno e in ooynn if uei morftlonng Min the seoon~,ta and fte ses Fr ths R.te voturnetwc calculationa Rof nentified LEAKAGE and identified LEAKAGE Is based on a density at room temrature of

- t ona denshyat operatingR t~ure of ZSdegrees F.

Inorder to rovide enhanced ssurance that the p EAKAGIlmitof LOO 3.4.1 is met in MODE 1.

ts pedo edyja an Nd Computer prog i Opernto of p and seoondaoys Item activities to de m Thits ye fcation methodolog is based on guidaice In ad ii n, on a monthly Isis, primary to secotdar k d ete edobasedong samples. /

Lb e ROS water inventory balance must be performed with the reactor at Qfio1~fe / .i;t 1 4, r eadystateoperat conditions and near operatin ressure.

'- i~ A ,isr ef SR is not required to be completinM S 3 54d until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of steady state operation nearoperating p been established.

Steady state operation is required to perform a proper inventory balance; calculations during maneuvering are not useful andO N ootefbuirersit Surveillance to be met when steady state is established. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

An early warning of pressure boundary LEAKAGE or unidentified LEAKAGE is provided by the automatic systems that monitor the containment atmosphere radioactivity and the containment sump level. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. These Jeakage detection systems are specified in LCO 3A.15, -RCS Leakagq Detection lnstrumentation.

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 OAr'JL CJIfCtt l..

~eirni.es the importance of early leakage detection in the prevention of 0

Sints.A Note under the Frequency column states that this SR is of p-i-i-. required to be performed during steady state operation.

o Catawba Units 1 and 2 8 34.13-5 Revision No.@ .3

INSERT C for B 3.4.13 Surveillance Requirements:

Note 2 states that this SR is not applicable to primary to secondary LEAKAGE because LEAKAGE of 150 gallons per day or lower cannot be measured accurately by an RCS water inventory balance.

RCS Operational LEAKAGE B 3.4.13 BASES -

SURVEILLANCE REQUJIREMiENTS (cog~tinued)

SR 3A.13.2; Ai t~ioidesthe means qsayto detennnG<PR~~~

{ noe~nlMOOE. Thle r uemnt to de m oft SG tube Ctytgiq 15 D) in a with Me Ste QneratorTube Supel Pf empgiiestheimorlnq ofSGtube integw~de though s

_ _ danoe annotbe pfetme-at normal o0atn condtis REFERENCES 1. 10 CFR 50. Appendix A, GDC 30.

2. Regulatory Guide 1A5, May 1973.

3. UFSAR, Section 15.

4. 10 CFR 50.36, Technical Specifications, (c)(2)(i;).

5. EPRI TR-104788-R2, "PWR Primary-to-Secondary Leak Guidelines," Revision 2. I

. N!C, e eoarct PramC_ 4%j< 1,1 egr.)

i

-  ::J Catawba Units 1 and 2 B 3A.13-6 Revision NoO X

INSERT D for B 3.4.13 Surveillance Requirements:

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 3.4.18, "Steam Generator (SG) Tube Integrity," should be evaluated. The 150 gallons per day limit is based on measurements taken at room temperature, with a correction factor applied to account for the fact that current safety analyses take the primary to secondary leak rate at reactor coolant conditions, rather than at room temperature.

The Surveillance is modified by a Note which states that this SR is not required to be completed until 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of steady state operation near operating pressure have been established. During normal operation the primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling.

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 primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents and reduction of potential consequences. A Note under the Frequency column states that this SR is only required to be performed during steady state operation.

I~~ S 3L 1 ~ SG Tube Integrity 3.4.18 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.18 Steam Generator (SG) Tube Integrity LCO 3.4.18 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 next plugged in accordance inspection.

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

Catawba Units 1 and 2 3.4.1 8-1 Amendment Nos.

SG Tube Integrity 3.4.18 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time of Condition A AND not met.

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

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.18.1 Verify SG tube integrity in accordance with the In accordance Steam Generator Program. with the Steam Generator Program SR 3.4.18.2 Verify that each inspected SG tube that Prior to entering satisfies the tube repair criteria is plugged in MODE 4 accordance with the Steam Generator following a SG Program. tube inspection Catawba Units 1 and 2 3.4.18-2 Amendment Nos.

Ve TS ecqes 8 3, SG Tube Integrity B 3.4.1 8 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.18 Steam Generator (SG) Tube Integrity BASES BACKGROUND 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 upon 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, NRCS 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 safety functions consistent with their licensing basis, including applicable regulatory requirements.

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

Specification 5.5.9, "Steam Generator (SG) Program," requires that a program be established and implemented to ensure that SG tube integrity is maintained. Pursuant to Specification 5.5.9, tube integrity is maintained when the SG performance criteria are met.

There are three SG performance criteria: structural integrity, accident induced leakage, and operational LEAKAGE. The SG performance criteria are described in Specification 5.5.9. Meeting the SG performance criteria provides reasonable assurance of maintaining tube integrity at normal and accident conditions.

Catawba Units 1 and 2 B 3.4.18-1 Revision No. 0

SG Tube Integrity B 3.4.1 8 BASES BACKGROUND (continued)

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

APPLICABLE The design basis accidents for which the primary to secondary SAFETY ANALYSES LEAKAGE is a pathway for release of activity to the environment include the main steam line break, SG tube rupture, reactor coolant pump locked rotor accident, single rod withdrawal accident, and rod ejection accident. The analysis of radiological consequences of these design basis accidents, except for a SG tube rupture, assumes that the total primary to secondary LEAKAGE from each SG initially is 150 gallons per day. Transient thermal hydraulic analyses of these design basis accidents determine the primary to secondary LEAKAGE changes (decreases or increases) that result from changing pressures and temperatures. These calculated values are used in the analyses of radiological consequences of these design basis accidents.

The source term in the primary coolant for some design basis accidents (e.g., reactor coolant pump locked rotor accident and rod ejection accident) is associated primarily with fuel rods calculated to be breached. For other design basis accidents (e.g.,

main steam line break and SG tube rupture), the source term in the primary coolant consists primarily of the levels of DOSE EQUIVALENT 1-131 radioactivity levels calculated for the design basis accident. This, in turn, is based on the limiting values in the Technical Specifications and postulated iodine spikes.

For accidents in which the source term in the primary coolant consists of the DOSE EQUIVALENT 1-131 activity levels, the SG tube rupture yields the limiting values for radiation doses at offsite locations. In the calculation of radiation doses following this event, the rate of primary to secondary LEAKAGE in the intact SGs is set equal to the operational LEAKAGE rate limits in LCO 3.4.13, "RCS Operational LEAKAGE.' For the ruptured SG, a double ended rupture of a single tube is assumed. Following the initiating event, contaminants in flashed and atomized break flow (the latter computed for time spans during which the tubes are calculated to be uncovered), as well as secondary coolant, may be released to the atmosphere. Before reactor trip, the accident analysis for the SG tube rupture assumes that these contaminants are released to the condenser and from there to the environment with credit taken for scrubbing of iodine contaminants in the condenser. Following reactor trip (and loss of offsite power), the accident analysis assumes that these contaminants are released to the environment through the SG power operated relief valves Catawba Units 1 and 2 B 3.4.18-2 Revision No. 0

SG Tube Integrity B 3.4.18 BASES APPLICABLE SAFETY ANALYSES (continued) and the main steam code safety valves until such time as the closure of these valves can be credited.

For other design basis accidents such as main steam line break, rod ejection accident, reactor coolant pump locked rotor accident, and uncontrolled rod withdrawal accident, the tubes are assumed to retain their structural integrity (i.e., they are assumed not to rupture). The LEAKAGE is assumed to be initially at the limit given in LCO 3.4.13.

The three SG performance criteria and the limits included in LCO 3.4.16, "RCS Specific Activity," for DOSE EQUIVALENT 1-131 in primary coolant, and in LCO 3.7.17, "Secondary Specific Activity,'

for DOSE EQUIVALENT 1-131 in secondary coolant, ensure the plant is operated within its analyzed condition. The dose consequences resulting from the most limiting design basis accident are within the limits defined in GDC 19 (Ref. 2), 10 CFR 100 (Ref. 3), or the NRC approved licensing basis (e.g., a small fraction of these limits or 10 CFR 50.67 (Ref. 4)).

SG 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 a 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 and any repairs made to it, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. The tube-to-tubesheet weld is not considered part of the tube.

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

Catawba Units 1 and 2 B 3.4.18-3 Revision No. 0

SG Tube Integrity B 3.4.18 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 under normal and accident conditions, and ensures structural integrity of the SG tubes under all anticipated transients included in the design specification.

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

6). 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." Significant is defined as, 'An accident loading condition other than differential pressure is considered significant when the addition of such loads in the assessment of structural integrity performance criterion causes a lower structural limit or limiting burst/collapse condition to be established."

The accident induced leakage performance criterion ensures that the primary to secondary LEAKAGE caused by a design basis accident, other than a SG tube rupture, is within the accident analysis assumptions. The accident analysis assumes that accident induced leakage does not exceed 150 gallons per day through each SG for a total of 600 gallons per day through all SGs. 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 Catawba Units 1 and 2 B 3.4.18-4 Revision No. 0

SG Tube Integrity B 3.4.18 BASES LCO (continued) this amount would not propagate to a SG tube rupture under the stress conditions of a loss of coolant accident 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 MODES 1, 2, 3, and 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 3.4.18.2. An evaluation of SG tube integrity of the affected tube(s) must be made. SG tube integrity is based on meeting the SG performance criteria described in the Steam Generator Program. The SG repair criteria define limits on SG tube degradation that allow for flaw growth between inspections while still providing assurance that the SG performance criteria will continue to be met. In order to determine if a SG tube that should have been plugged has tube integrity, an evaluation must be completed that demonstrates that the SG performance criteria will continue to be met until the next SG tube inspection. The tube integrity determination is based on the estimated condition of the tube at the time the situation is discovered and the estimated growth of the degradation prior to the next SG tube inspection. If it is determined that tube integrity is not being maintained, Condition B applies.

Catawba Units 1 and 2 B 3.4.18-5 Revision No. 0

SG Tube Integrity B 3.4.18 BASES ACTIONS (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 outage 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 tube 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 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

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

SURVEILLANCE SR 3.4.18.1 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.

Catawba Units 1 and 2 B 3.4.18-6 Revision No. 0

SG Tube Integrity B 3.4.1 8 BASES SURVEILLANCE REQUIREMENTS (continued)

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 3.4.18.1. The Frequency is determined in part by the operational assessment and other limits in the Steam Generator 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 5.5.9 contains prescriptive requirements concerning inspection intervals to provide added assurance that the SG performance criteria will be met between scheduled inspections.

SR 3.4.18.2 During a SG inspection, any inspected tube that satisfies the Steam Generator Program repair criteria is removed from service by plugging. The tube repair criteria delineated in Specification 5.5.9 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). Ref. 1 and Ref. 7 provide guidance for performing operational assessments to verify that the tubes remaining in service will continue to meet the SG performance criteria.

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

Catawba Units 1 and 2 B 3.4.1 8-7 Revision No. 0

SG Tube Integrity B 3.4.18 BASES REFERENCES 1. NEI 97-06, "Steam Generator Program Guidelines."

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 100.

4. 10 CFR 50.67.

5. ASME Boiler and Pressure Vessel Code, Section 1II, Subsection NB.

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

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

Catawba Units 1 and 2 B 3.4.18-8 Revision No. 0

Programs and Manuals 5.5 5.5 Program and Manuals (continued) 5.5.8 Inservice Testinc Proqram C

This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components including applicable supports. The program sHall include the following:

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

-- -ASME Boiler and Pressure Vessel Code and applicable Required Frequencies for Addenda terminology for performing inserice testing inservice testing activities activities Weeldy At least once per 7 days Monthly At least once per 31 days I

Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days .

Biennially or every 2 years At least once per 731 days

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

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

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

5.5.9 Steam Generator LSG) Qubne31nc)rooram Qhsprogra Prvs controls for teinlservie in1' ctin of steam g n rto tubes to eisr that the structural if terity of this poto:= h RSi maintained. Te program for inserc inspection of stimgenerator tes is

)based on a of Regul toy Guide 1.83, R

~otiain ision 1. The p oram (continued)

Catawba Units I and 2 55-6 Amendment Nos. os.D

Programs and Manuals 5.5 Each t e rshall be detemine P during shutdo by se Inspecting at least the inimumo ea generators specified in t5.5.9GenetrTube Samp e Selectiona I /

E steam generator tube mnum ize inspection result classificationb he owesponding action required hnd be as specifed in Table 55-2. The

/inserice inspection of steam genesator shall be perfonmed at the frequencies specified in Specification .5.9.3 and the inspected tubes shalt be verified acceptable per the acoep criteria of Specification 5.5.9.4. Thestbe selected for each inseniice inspect shall indude at least 30%of the total number of tubes in all steam genertors; the tubes selected for these inspecion shall be selected on a random is except:

a. Where expenienoe in plants with wlarsimilar water chemistry indi tes critical areas to be ed, then at least 501% of the tubes in ed shall be from these ticaI areas;

b. The first sample tubes selected for each inservice inspecti (subsequent to e preservice inspection) of each steam gen rator shall include:

1. All n iplugged tubes that previously had detectape wall pe trations (greater than 20%).

2. T in those areas where experience has ibes icated potential roblems, and l3 A tube inspection (pursuant to Specificaon 55.9.4-a8) shall be performed on each selected tube If a selected tube does not permit the passage of the eddy curr probe for a tube inspection, this shall be recorded a an adjacent tube shall be selected and subjected to a tube ' on.

c The tubes selected as the second and iird samples (it required by Table 5.5-2) during each insennce o may be subjected to a partial tube inspection provided:

1. The tubes selected for U se samples include the tubes from those areas of the tube ieet array viere tubes with imperfections were pr ouslyfound, and (continued)

Catawba Units I and 2 55-7 Amendment Nos. (i )

Programs and Manuals 5.5 Pmramns and Manuals

{5.5.2 Stam GyeratrT~eSam~l Selection and (nspectionX§nne)

The inspections include those portions o tubes where

/mperfections were prevosly found.

Thresuts of each sample inspection shall be ted into one of the following eecategories: ,

/Cateonf ledionResults

/ 1 Less than 5gmof the total tubes Inspected are

/degraded and none of the inspected tubes

/ ~~~are eea.\

G2 One more tubes. but not more than 1% of the totubes inspected are defective, or between 5%

a 10% of the total tubes inspected are degraded

/-3 More than 10% of the total tubes inspected are degraded tubes or more than 1% of the inspect tubes are defective.

Note: In all insp ons previously degraded tubes must exhibit significan (greater n 10%) further walg penetrations to be included in the ye percene calculations /

5.5.9.3 Inspectio r encies The a ye required inservice inspections of steam generator tus shall be pe ed at the following frequencies:

a The first inservice inspection after steam generator r placement shall be perfo med after at least 6 Effective Full Power M is but within 24 calendar months of initial criticality after steam erator replacement (Unit 1). The first inservice inspection shall be Xrfomed after 6 Effective Full Power Months but within 24 calendar IS of initial criticality (Unit 2). Subsequent inservice inspections shall performed at intervals of not less than 12 nor more than 24 calen months after the previous inspection. If two consecutive inspect not including the preservice inspection, result in all inspection tesut falling into the C-1 category or if two consecutive inspections demonstr te that previously observed degradation has not continued and additional degradation has occurred, the inspection interval m tee extended to a maximum of once per 40 months; (continued)

Catawba Units

• and 2 5.5-8 Amendment Nos

j Prognrms and Manuals 5.5 Programs and Manuals 55.9.3 InpR eon~rencies (oontinued

b. If th wsults of the insenvioe inspection of a steam enerator conducted in ccordance wfi Table 5.5-2 at 40-mont inte is fall in Category C-3, inspection frequency shall be increased to eastonce per 20 mons. The increase in nspection f eqU apply until the subsequent inspections satisfy the creria o pecificat;on S.S3 the.

interal may then be extended to a mam of once per 40 months; and

c. Additional, unscheduled inseio ons shatl be performed on each steam generator in accordance th tiat sample inspection specified in Table 5.5-2 dung the udduent to any of the following conditions:

1ubes leaks (not including leaks originating from tube-totube eet welds) in excess of the limits of Specification 3.4 3/

2. A seismic rrence greater than the Operating Basis Earthqua,/

3. A Ioss ant accident requiring actuation of the Engineered Safe Or oeatues,

4. A steam line or feedwater line break.

The provis"io f SR 3.0.2 are applicable to the SG Tube Surveillance rogram test fre;e 5.5.9.4 ceane Criteria

a. As used in this specification:

/ 1. Inmperfection means an exception to the tensions, finish or contour of a tube from that required b abrcation drawings or specifications Eddy-current testing dications below 20% of the nominal tube wall thickness, if det able, may be considered as imperfections;

2. Degradation means a se inducdcracking, wastage, wear or general corrosion occurron either inside or outside of a tube; (continued)

Catawba Units 1 and 2 5-5-9 Amendment Nos.( )

Programs and Manuals I 5.5 5.5 Programs and Manuals N

5.5.9.4 o Accenta Criteria (continued)

Degraded Tube means a tube containin impfections greater than or equal to 20% of the nomifnal t wall thickness caused by degradation;

4.  % degradation means the pertage of the tube wall thickness affected or removed by deg tion;

5. Defect means an inperf of such severity that it exceeds the plugging Omit. A tube taming a defect Is defective;

6. PLuqqing limit m the imperfection depth at or beyond which the tube shall b removed from service by plugging. The plugging rimit is equal 40% of the nominal tube wall thickness.

7. Unservi ble describes the condition of a tube if it leaks or contaipa defect large enough to affect its stnictural integrty in/

the e nt of an Operating Basis Earthquake, a loss-of -coolant a ident, or a steam line or feedwater line break as specifi n

.9.3.c. above;

8. Tube Inspection means an inspection of the steam ge rator tube from the point of entry completely around the U-ben to the point of exit; and

9. Preservice Inspection means an inspection o fullIfe length of each tube in each steam generator perfo d by eddy current techniques prior to service to establish a seline condition of the tubing. This inspection shall be perfo pror to initial POWER OPERATION using the equipment a techniques expected to be used during subsequent inservice i

b. The steam generator shall be deternm'ed OPERABLE after completing the corresponding actions required y Table 5.5-2.

Lar (continued)

Catawba Units 1 and 2 5 5-10 Amendment Noas.

Programs and Manuals 5.5 WNllY d NIMER OFSTEAM GENERATORS T ltalspcDURING INSERVICE ISPEcun Pre. e+o. No /Yes.l No. of Generators per tInit Four Inspection after the Two Steam Generator Reptacement

/ ({JQ 1)// I First Insenice Inspection (Unit 2)

Seoond & Subsequent (nsevizce One' One Inspections Tabte Notation I The inservice inspectionaybe limited to one steam generator on a rotating ledue encompassing 3 N % the tubes (where N is the number of steam generam in the unit) if the results of the fimst Or evious inspections indicate that aft steam generators e performing in a like

,manner. Note Ulat r~de some ctrcumstances. the opoemting conditions inva or more steam generators may bludto be more severe than those in other steam g hrators. Und~er such circumstances tt~apesequence sW[l be modified to i nspect the natsevere cotndtions.

2. Each of the o),e two steam generators not isected during thle firs iaevz nspect'ion after the steam gento replacement shat be inspected durnag thie s dthird inspections (Unit 1).

Each of ffoar two steam geneators not inspected duZte9s n einspection shaUt be

\ hspectefd tag e seoond and ffiisd inspectioas (Unit 2) IThef~st and subsequent iaspectt-ons l hal

'a isttct-on S6w dsced tr1 bove U amtT Aw Catawtba Unists 1 and 2 5.5-11 Amendmnentt No s.4~ )

I V (iV Programs and Manuals 5-5 ff _

(I

~/ TABLE 5.5-2 Sui 1 GENERATOR TUBE INSPECrION N

-1sTSAMPLE 3sEwnoN SAMPLE INSPECION 3RD SAMPLE I

'N SawA Size Result l4 Result~ Action neqviied RlesullAtgZeiad

.n _ , , , I IAof Sriiumuru I 9VA

-I i IVA IVA eWA perSG tubes

/17Nn A, /

0

_ .. _-- ,r ....

I C-2 Plug C.1 Hone HWA tubes and additional 2S tubesGintfis SG

/ C-2 Puggcie C-1 None

/-2 Plug defective tubes C-3 Pedonn action for C-3 result of first sample C-3 Pelormo action for NfA N/A 0-3 result of first C-3 InSl ts NGplug all ia this

.AII other SGs are C-1 sample None NVA N/A /~

defective tubes and inspect 2S tubes in cach other SG.

Prompt notification to NRC pursuant to 10CFR50.72 (b)(2)

Some SGs Perform action or WA

/NA C-2 but no additional SGs are C-3 0-2 result of second sample _

I Additional Inspecl all tubes V NrA NWA SG is C-3 each SG and pt defective tubgE Notificatfiorn NRC pursuanttf 10CF7.72 (bK2)

S = 3N/n % Where N is tte number of steam gene /trs in the untt, and n is the number of steam I generators inspected dunng an iksfl&ton-1-1 Catawba Units 1 and 2 5.5-12 Amendment Nos. 02F~)

A k INSERT A for TS 5.5.9, Steam Generator (SG) Program:

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

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The 'as found" condition refers to the condition of the tubing during a SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging of tubes. Condition monitoring assessments shall be conducted during each outage during which the SG tubes are inspected or plugged to confirm that the performance criteria are being met.

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

1. Structural integrity performance criterion: All inservice SG tubes shall retain structural integrity over the full range of normal operating conditions (including startup, operation in the power range, hot standby, and cooldown, and all anticipated transients included in the design specification) and design basis accidents. This includes retaining a safety factor of 3.0 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 through each SG for a total of 600 gallons per day through all SGs.

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.

9 1^

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. The number and portions of the tubes inspected and method of inspection shall be performed with the objective of detecting flaws of any type (for example, 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 requirements d.1, d.2, d.3, and d.4 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. For Unit 1, inspect 100% of the tubes at sequential periods of 144, 108, 72, and, thereafter, 60 Effective Full Power Months (EFPM). 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 EFPM or three refueling outages (whichever is less) without being inspected.

3. For Unit 2, inspect 100% of the tubes at sequential periods of 120, 90, and, thereafter, 60 EFPM. The first sequential period shall be considered to begin after the first inservice inspection of the SGs. In addition, inspect 50% of the tubes by the refueling outage nearest the midpoint of the period and the remaining 50% by the refueling outage nearest the end of the period. No SG shall operate for more than 48 EFPM or two refueling outages (whichever is less) without being inspected.

4. 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 EFPM 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 crack(s), then the indication need not be treated as a crack.

e. Provisions for monitoring operational primary to secondary LEAKAGE.

Reporting Requirements 5.6 5.6 Reporting Requirements (continued) 5.6.7 PAM Report When a report is required by LCO 3.3.3, "Post Accident Monitoring (PAM)

Instrumentation," a report shall be submitted within the following 14 days. The report shall outline the preplanned alternate method of monitoring, the cause of the inoperability, and the plans and schedule for restoring the instrumentation channels of the F tion to OPERABLE status.

5.6.8 Steam Generator ube Inspection Report a henumber of tubes plugge in each steam gener rshall be reported o the NRC within 15 days f owing completion of t program;

b. The complete results oft Steam Generator Tub Surveillance Program shall be reported to the C within 12 months fo owing the completion of the program and shall i ude:

1. Number and xtent of tubes inspected

2. Location a d percent of wall-thickne penetration for each indicationf an imperfection, and

3. Identifi tion of tubes plugged.

c. The result/of inspections of steam ge erator tubes which fall i to Category -3 shall be reported to the RC within 30 days pri to the restart the unit following the inspe ion. This report shall ovide a descri ion of the tube degradation nd corrective measure taken to prevyt recurrence.

Catawba Units 1 and 2 5.6-6 Amendment Nos4i Y2O

0- I*-.

INSERT B for TS 5.6.8, Steam Generator (SG) Tube Inspection Report:

A report shall be submitted within 180 days after the initial entry into MODE 4 following completion of the inspection. The report shall include:

a. The scope of inspections performed on each SG,

b. Active degradation mechanisms found,

c. Non-destructive examination techniques utilized for each degradation mechanism,

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

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

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

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