ML12038A173

Proposed Tech Specs Amendment TS 3.4.13, TS 5.5.9, TS 5.6.8, License Amendment Request to Revise TS for Permanent Alternate Repair Criteria

ML12038A173
Person / Time
Site:	Catawba
Issue date:	02/01/2012
From:	Morris J Duke Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML12038A173 (17)

Text

SEnergy Duke JAMES R.MORRIS Vice President Duke Energy Catawba Nuclear Station 4800 Concord Road York, SC 29745 803-701-4251 803-701-3221 fax February 1, 2012 10 CFR 50.90 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555

Subject:

Duke Energy Carolinas, LLC (Duke Energy)

Catawba Nuclear Station, Units 1 and 2 Docket Numbers 50-413 and 50-414 Proposed Technical Specifications (TS) Amendment TS 3.4.13, "RCS Operational LEAKAGE" TS 5.5.9, "Steam Generator (SG) Program" TS 5.6.8, "Steam Generator (SG) Tube Inspection Report" License Amendment Request to Revise TS for Permanent Alternate Repair Criteria

Reference:

Letters from Duke Energy to NRC, same subject, dated June 30, 2011, July 11, 2011, and January 12, 2012 The reference letters comprise Duke Energy's request for an amendment to Catawba Facility Operating Licenses NPF-35 and NPF-52 and the subject TS. The proposed amendment constitutes a redefinition of the SG tube primary to secondary pressure boundary for Unit 2 and defines the safety significant portion of the tube that must be inspected or plugged. The technical justification for the amendment request is based in part on Westinghouse WCAP-17330-P, Rev. 1, "H*: Resolution of NRC Technical Issue Regarding Tubesheet Bore Eccentricity (Model F/Model D5)".

On January 26, 2012, a telephone conference call was held among representatives of Duke Energy and the NRC. The purpose of this call was to discuss the need for the continuation of regulatory commitments associated with previous one-cycle amendments. As a result of this call, Duke Energy is making the following two regulatory commitments associated with the permanent amendment request:

Regulatory Commitment 1: For Unit 2, Catawba commits to monitor for tube slippage as part of the SG tube inspection program required by TS 5.5.9. The results of this monitoring will be included in the report required by TS 5.6.8j.

Regulatory Commitment 2: For Unit 2, for the Condition Monitoring (CM) assessment, the component of operational leakage from the prior cycle from below the H* distance will be multiplied by a factor of 3.27 and added to the total accident leakage from any other source and compared to the allowable accident induced leakage limit. For the www. duke-energy com

U.S. Nuclear Regulatory Commission Page 2 February 1, 2012 Operational Assessment (OA), the difference between the allowable accident induced leakage and the accident induced leakage from sources other than the tubesheet expansion region will be divided by 3.27 and compared to the observed operational leakage. An administrative operational leakage limit will be established to not exceed the calculated value in the event that TS 3.4.13 is no longer bounding.

Also included with this letter is a copy of the reprinted TS and Bases pages associated with this amendment request (refer to the attachment).

The original regulatory evaluation provided in support of the proposed amendment is unchanged as a result of this supplement.

In accordance with 10 CFR 50.91, Duke Energy is notifying the State of South Carolina of this license amendment request supplement by transmitting a copy of this letter and its attachment to the designated state official.

Should you have any questions concerning this information, please contact L.J. Rudy at (803) 701-3084.

Very truly yours, Morris LJR/s Attachment

U.S. Nuclear Regulatory Commission Page 3 February 1, 2012 James R. Morris 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.

Jaml4 R. Morris, Vice President Subscribed and sworn to me:

Date Notrylubic My commission expires: 7 -o - 2_

Date SEAL

U.S, Nuclear Regulatory Commission Page 4 February 1, 2012 xc (with attachment):

V.M. McCree Regional Administrator U.S, Nuclear Regulatory Commission - Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, GA 30303-1257 G.A. Hutto, III Senior Resident Inspector (CNS)

U.S, Nuclear Regulatory Commission Catawba Nuclear Station J.H. Thompson (addressee only)

NRC Project Manager (CNS)

U.S. Nuclear Regulatory Commission One White Flint North, Mail Stop 8-G9A 11555 Rockville Pike Rockville, MD 20852-2738 S.E. Jenkins Manager Radioactive and Infectious Waste Management

-Division of Waste Management South Carolina Department of Health and Environmental Control 2600 Bull St.

Columbia, SC 29201

ATTACHMENT Reprinted TS and Bases Pages

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

a. No pressure boundary LEAKAGE;

b. 1 gpm unidentified LEAKAGE;

c. 10 gpm identified LEAKAGE; and

d. 150 gallons per day (Unit 1) and 45 gallons per day (Unit 2) primary to secondary LEAKAGE through any one steam generator (SG).

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

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

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

B. Required Action and B. 1 Be in MODE 3. 6 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.

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 Pressure boundary LEAKAGE exists.

OR Primary to secondary LEAKAGE not within limit.

Catawba Units 1 and 2 3.4.13-1 Amendment Nos.

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

---

NOTE ------

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

2. Not applicable to primary to secondary LEAKAGE. state operation Verify RCS Operational LEAKAGE within limits by In accordance with performance of RCS water inventory balance. the Surveillance Frequency Control Program

+

SR 3.4.13.2 -NOTE ---------------- NOTE --------

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

---

during steady state operation Verify primary to secondary LEAKAGE is < 150 gallons In accordance with per day (Unit 1) and < 45 gallons per day (Unit 2) through the Surveillance any one SG. Frequency Control Program Catawba Units 1 and 2 3.4.13-2 Amendment Nos.

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

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

1. For Unit 2 only, tubes with service-induced flaws located greater than 14.01 inches below the top of the tubesheet do not require plugging. Tubes with service-induced flaws located in the portion of the tube from the top of the tubesheet to 14.01 inches below the top of the tubesheet shall be plugged upon detection.

d. Provisions for SG tube inspections. Periodic SG tube inspections shall be performed. For Unit 1, 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. For Unit 2, 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 14.01 inches below the top of the tubesheet on the hot leg side to 14.01 inches below the top of the tubesheet on the cold leg side, and that may satisfy the applicable tube repair criteria. 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.

(continued)

Catawba Units 1 and 2 5.5-7a Amendment No.

Programs and Manuals 5.5 5.5 Programs and Manuals 5.5.9 Steam Generator (SG) Pro-gram (continued)

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. For Unit 1, 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). For Unit 2, if crack indications are found in any SG tube from 14.01 inches below the top of the tubesheet on the hot leg side to 14.01 inches below the top of the tubesheet on the cold leg side, 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 (continued)

Catawba Units 1 and 2 5.5-8 Amendment Nos.

Reporting Requirements 5.6 5.6 Reporting Requirements 5.6.8 Steam Generator (SG) Tube Inspection Report (continued)

h. For Unit 2, the primary to secondary LEAKAGE rate observed in each SG (if it is not practical to assign leakage to an individual SG, the entire primary to secondary LEAKAGE should be conservatively assumed to be from one SG) during the cycle preceding the inspection which is the subject of the report, For Unit 2, the calculated accident leakage rate from the portion of the tubes below 14.01 inches from the top of the tubesheet for the most limiting accident in the most limiting SG. In addition, if the calculated accident leakage rate from the most limiting accident is less than 3.27 times the maximum primary to secondary LEAKAGE rate, the report shall describe how it was determined, and

j. For Unit 2, the results of monitoring for tube axial displacement (slippage). If slippage is discovered, the implications of the discovery and corrective action shall be provided..

Catawba Units 1 and 2 5.6-6 Amendment Nos.

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 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) describes 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% 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 include 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. 7

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE SAFETY ANALYSES (continued)

The safety analysis (Ref. 3) for an event resulting in steam discharge to the atmosphere assumes that primary to secondary LEAKAGE from each steam generator (SG) is 150 gallons per day. Any event in which 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 uncontrolled 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 below the 10 CFR 50.67 limits (Ref. 9) and the limits in Regulatory Guide 1.183 (Ref. 10) for these 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. 7

RCS Operational LEAKAGE B 3.4.13 BASES LCO (continued) can detect within a reasonable time period. Violation of this LCO could result in continued degradation of the RCPB, if the LEAKAGE is from the pressure boundary.

c. Identified LEAKAGE Up to 10 gpm of identified LEAKAGE is considered allowable because LEAKAGE is from known sources that do not interfere with detection of unidentified or total LEAKAGE and is well within the capability of the RCS Makeup System. Identified LEAKAGE includes LEAKAGE captured by the pressurizer relief 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. Primary to Secondary LEAKAGE through Any One SG The limit of 150 gallons per day (Unit 1) and 45 gallons per day (Unit 2) 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 limit for Unit 2 has been permanently reduced as a result of the SG tube alternate repair criteria that has been implemented for this unit.

The primary to secondary LEAKAGE measurement is based on the methodology 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.

Catawba Units 1 and 2 B 3.4.13-3 Revision No. 7

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

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

LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," measures leakage through each individual PIV and can impact this LCO. Of the two PIVs in series in each isolated line, leakage measured through one PIV does not result in RCS LEAKAGE when the other is leak tight. If both valves leak and result in a loss of mass from the RCS, the loss must be included in the allowable unidentified LEAKAGE.

ACTIONS A.1 Unidentified LEAKAGE or identified LEAKAGE in excess of the LCO limits 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.

B.1 and B.2 If any pressure boundary LEAKAGE exists, or if primary to secondary LEAKAGE is not within limit, or if unidentified LEAKAGE or identified LEAKAGE cannot 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 orderly manner and without challenging plant systems. In MODE 5, the pressure stresses acting on the RCPB are much lower, and further deterioration is much less likely.

Catawba Units 1 and 2 B 3.4.13-4 Revision No. 7

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.1 REQUIREMENTS Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity of the RCPB is maintained. Pressure boundary LEAKAGE would at first appear as unidentified LEAKAGE and can only be positively identified by inspection. It should be noted that LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE. Unidentified LEAKAGE and identified LEAKAGE are determined by performance of an RCS water inventory balance. For this SR, the volumetric calculation of unidentified LEAKAGE and identified LEAKAGE is based on a density at room temperature of 77 degrees F.

The Surveillance is modified by two Notes. The RCS water inventory balance must be performed with the reactor at steady state operating conditions and near operating pressure. Therefore, Note 1 indicates 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.

Steady state operation is required to perform a proper inventory balance; calculations during maneuvering are not useful and Note 1 requires the Surveillance to be met when steady state is established. For RCS operational LEAKAGE determination by water inventory balance, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

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.

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 leakage detection systems are specified in LCO 3.4.15, "RCS Leakage Detection Instrumentation."

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. A Note under the Frequency column states that this SR is only required to be performed during steady state operation.

Catawba Units 1 and 2 B 3.4.13-5 Revision No. 7

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.13.2 This SR verifies that primary to secondary LEAKAGE is less than or equal to 150 gallons per day (Unit 1) and less than or equal to 45 gallons per day (Unit 2) 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 (Unit 1) and 45 gallons per day (Unit 2) limit is based on measurements taken at room temperature.

The primary to secondary leak rate assumed in the safety analyses is taken also 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 Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. A Note under the Frequency column states that this SR is only required to be performed during steady state operation.

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

2. Regulatory Guide 1.45, May 1973.

3. UFSAR, Section 15.

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

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

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

7. UFSAR, Section 18, Table 18-1.

8. Catawba License Renewal Commitments, CNS-1274.00-00-0016, Section 4.27.

9. 10 CFR 50.67.

Catawba Units 1 and 2 B 3.4.13-6 Revision No. 7

RCS Operational LEAKAGE B 3.4.13 BASES REFERENCES (continued)

10. Regulatory Guide 1.183, July 2000.

Catawba Units 1 and 2 B 3.4.13-7 Revision No. 7