ML083260573

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Technical Specification Bases Changes
ML083260573
Person / Time
Site: Catawba  Duke Energy icon.png
Issue date: 11/12/2008
From: Morris J
Duke Energy Carolinas
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML083260573 (26)
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Text

PDuke EEnergy Carolinas JAMES R. MORRIS, VICE PRESIDENT Duke Energy Carolinas, LLC Catawba Nuclear Station 4800 Concord Road / CN01 VP York, SC 29745 803-701-4251 803-701-3221 fax November 12, 2008 U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001

Subject:

Duke Energy Carolinas, LLC Catawba Nuclear Station, Units 1 and 2 Docket Nos.

50-413 and 50-414 Technical Specification Bases Changes Pursuant to 10CFR 50.4, please find attached changes to the Catawba Nuclear Station Technical Specification Bases.

These Bases changes were made according to the provisions of 10CFR 50.59.

Any questions regarding this information shouldbe directed to L.

J.

Rudy, Regulatory Compliance, at (803)701-3084.

I certify that I am a duly authorized officer of Duke Energy Corporation and that the information contained herein accurately represents changes made to the Technical Specification Bases.

since the previous submittal.

James R. Morris Attachment kco 1 0041) www. duke-energy. com

U.S. Nuclear Regulatory Commission November 12, 2008 Page 2 xc:

Luis Reyes U.S.

Nuclear Regulatory Commission Atlanta-Federal Center 61 Forsyth St.,

SW, Suite 23T85

Atlanta, GA 30303 J.

F. Stang, Jr.,

NRR Project Manager U.S. Nuclear Regulatory.Commission One White Flint North, Mail Stop 8 G9A 11555 Rockville Pike Rockville, MD 20852-2.738 A.T. Sabisch Senior Resident Inspector Catawba Nuclear Station

U.S. Nuclear Regulatory Commission November 12, 2008 Page 3 bxc:

w/o attachment NCMPA-1 NCEMC PMPA w/attachment Electronic Licensing Library ECO50 RGC File CN01RC Master File CN-801.01 CN04DM f

Duke DUKE ENERGY CAROLINAS, LLC Catawba Nuclear Station r OEnergy@

  • 4800 Concord Road Carolinas York, SC 29745 November 12, 2008 Re:

Catawba Nuclear Station Technical Specifications Bases Please replace the corresponding pages in your copy of the Catawba Technical Specifications Manual as follows:

REMOVE THESE PAGES INSERT THESE PAGES LIST OF EFFECTIVE PAGES Pages 16,22,25,26,29,30 & 32 Pages 16,22,25,26,29,30 & 32 TAB 3.3.1 B 3.3.1-47 thru B 3.3.1-48 B 3.3.1-47 thru B 3.3.1-48 TAB 3.4.13 B 3.4.13-3 thru B 3.4.13-7 B 3.4.13-3 thru B 3.4.13-7 TAB 3.6.8 B 3.6.8-5 thru B 3.6.8-5 B 3.6.8-5 thru B 3.6.8-5 TAB 3.6.9 B 3.6.9-5 thru B 3.6.9-6 B 3.6.9-5 thru B 3.6.9-6 www. duke-energy. com

TAB 3.7.12 B 3.7.12-1 thru B 3.7:12-2 B 3.7.12-1 thru B 3.7.12 -2 TAB 3.8.1 B 3.8.1-13 thru B 3.8.1-14 B 3.8.1-13 thru B 3.8.1-14 If you have any questions concerning the contents of this Technical Specification update, contact Betty Aldridge at (803)701-3758.

Ranar, Manager, Regulatory Compliance

Page Number B 3.3.1-16 B 3.3.1-17 B 3.3.1-18 B 3.3.1-19 B 3.3.1-20 B 3.3.1-21 B 3.3. 1-22 B 3.3.1-23 B 3.3.1-24 B 3.3.1-25 B 3.3.1-26 B 3.3.1-27 B 3.3.1-28 B 3.3.1-29 B 3.3.1-30 B 3.3.1-31 B 3.3.1-32 B 3.3.1-33 B 3.3.1-34 B 3.3.1-35 B 3.3.1-36 B 3.3.1-37 B 3.3.1-38 B 13.31-39 B 3.3.1-40 B 3.3.1-41 B 3.3.1-42 B 3.3.1-43 B 3.3.1-44 B 3.3.1-45 B 3.3.1-46 B 3.3.1-47 Amendment Revision 0 Revision 0 Revision 2 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 1

.Revision I Revision 0 Revision 0 Revision 0 Revision 1 Revision 1

  • Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 1 Revision 1 Revision 0 Revision 2 Revision 2 Revision 2 Revision Date 9/30/98 9/30/98 12/19/03 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/ 98 9/30/98 9/30/98 8/13/99 8/13/99 9/30/98 9/30/98 9/30/98 7/29/03 7/29/03 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 5/10/05 5/10/05

.9/30/98 6/13/05 6/13/05 8/27/08 Catawba Units 1 and 2Pae18/70 Page 16 8/27/08

Page Number B 3.4.12-11 B 3.4.12-12 B 3.4.12-13 B 3.4.13-1 B 3.4.13-2 B 3.4.13-3 B 3.4.13-4 B 3.4.13-5 B 3.4.13-6 B-3.4.13-7 B 3.4.14-1 B 3.4.14-2 B 3.4.14-3 B 3.4.14-4 B 3.4.14-5 B 3.4.14-6 B 3.4.15-1 B 3.4.15-2 B 3.4.15-3 B 3.4.15-4 B 3.4.15-5 B 3.4.15-6 B 3.4.15-7 B 3.4.15-8 B 3.4.15-9 B 3.4.15-10 B 3.4.16-1 B 3.4.16-2 B 3.4.16-3 B 3.4.16-4 B 3.4.16-5 B 3.4.16-6 B 3.4.17-1 B 3.4.17-2 Amendment Revision 2 Revision 1 Revision 1 Revision 0 Revision 2 Revision 2 Revision 1 Revision 3 Revision 5 Revision 0 Revision 0 Revision 1 Revision 0 Revision 0 Revision 0 Revision 1 Revision 2 Revision 2 Revision 3 Revision 2 Revision 2 Revision 4 Revision 1 Revision 1 Revision 1 Revision 0 Revision 1 Revision 1 Revision 2 Revision 2 Revision 2 Revision 1 Revision 0 Revision 0 Revision Date 4/29/04 4/29/04 4/29/04 9/30/98 3/13/08 8/27/08 1/13/05 1/13/05 8/27/08 8/27/08 9/30/98 2/26/99 9/30/98 9/30/98 9/30/98 2/26/99 7/25/07 7/25/07 7/25/07 7/25/07 7/25/07 7/25/07 7/25/07 7/25/07 7/25/07 7/25/07 3/13/08 3/13/08 3/13/08 3/13/08 3/13/08 3/13/08 9/30/98 9/30/98 Catawba Units 1 and 2 Page 22 8/27/08

Page Number B 3.6.3-13 B 3.6.3-14 B 3.6.3-15 B 3.6.4-1 B 3.6.4-2 B 3.6.4-3 B 3.6.4-4 B 3.6.5-1 B 3.6.5-2 B 3.6.5-3 B 3.6.5-4 B 3.6.6-1 B 3.6.6-2 B 3.6.6-3 B 3.6.6-4 B 3.6.6-5 B 3.6.6-6 B 3.6.6-7 B 3.6.8-1 B 3.6.8-2 B 3.6.8-3 B 3.6.8-4 B 3.6.8-5 B 3.6.9-1 B 3.6.9-2 B 3.6.9-3 B 3.6.9-4 Amendment Revision 3 Revision 1 Revision 0 Revision 0 Revision 1 Revision 0 Revision 0 Revision 0 Revision 1 Revision 1 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 2 Revision 1 Revision 1 Revision 0 Revision 2 Revision 2 Revision 1 Revision 1 Revision 2 Revision 1 Revision 1 Revision Date 12/05/05 7/31/01 9/30/98 9/30/98 2/26/01 9/30/98 9/30/98 9/30/98 4/26/00 4/26/00 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 4/26/00 4/26/00 4/26/00 9/30/98 3/01/05 4/29/04 8/27/08 5/05/00 3/01/05 5/05/00 5/05/00 I ý Catawba Units 1 and 2 Peige 25 j

8/27/08

Page Number B 3.6.9-5 B 3.6.9-6 B 3.6. 10-1 B 3.6.10-2 B 3.6.10-3 B 3.6.10-4 B 3.6.10-5 B 3.6.10-6 B 3.6.11-1 B 3.6.11-2 B 3.6. 11-3 B 3.6.11-4 B 3.6.11-5 B 3.6.12-1 B 3.6.12-2 B 3.6.12-3 B 3.6.12-4 B 3.6.12-5 B 3.6.12-6 B 3.6.12-7 B 3.6.12-8 B 3.6.12-9' B 3.6.12-10 B 3..6.12-11 B 3.6.13-1 B 3.6.13-2 B 3.6.13-3 B 316.13-4 B 3.6.13-5 B 3.6.13-6 B 3.6.13-7 B 3.6.13-8 Amendment Revision 4 Revision 2 Revision 1 Revision 1 Revision 1 Revision 1 Revision 1 Revision 1 Revision 0 Revision 0 Revision 0 Revision 1 Revision 2 Revision 3 Revision 2 Revision 3 Revision 3 Revision 2 Revision 4 Revision 3 Revision 2 Revision 3 Revision 2 Revision 1 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 2 Revision Date 8/27/08 2/26/01 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 9/30/98 9/30/98 9/30/98 2/26/99 2/26/99 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 12/4/06 Catawba Units 1 and 2Pae28/70 Page 26 8/27/08

Page Number B 3.7.9-2 B 3.7.9-3 B 3.7.9-4 B 3.7.10-1 B 3.7.10-2 B 3.7.10-3 B 3.7.10-4 B 3.7.10-5 B 3.7.10-6 B 3.7.10-7 B 3.7.11-1 B 3.7.11-2 B 3.7.11-3 B 3.7.11-4 B 3.7.12-1 B 3.7.12-2 B 3.7.12-3 B 3.7.12-4 B 3.7.12-5 B 3.7.12-6 B 3.7.12-7 B 3.7.13-1 B 3.7.13-2 B 3.7.13-3 B 3.7.13-4 B 3.7.13-5 B 3.7.14-1 B 3.7.14-2 B 3.7.14-3 B 3.7.15-1 B 3.7.15-2 B 3.7.15-3 Amendment Revision 2 Revision 1 Revision 1 Revision 2 Revision 4 Revision 6 Revision 4 Revision 5 Revision 3 Revision 3 Revision 0 Revision 1 Revision 1 Revision 1 Revision 3 Revision 2 Revision 2 Revision 2 Revision 2 Revision 1 Revision 0 Revision 3 Revision 3 Revision 2 Revision 2 Revision 2 Revision 1 Revision 0 Revision 1 Revision 1 Revision 1 Revision 1 Revision Date 9/25/06 9/25/06 9/25/06 9/30/05 3/13/08 3/13/08 9/30/05 9/30/05 9/30/05 9/30/05 9/30/98 4/23/02 4/23/02 4/23/02 8/27/08 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 9/30/05 3/13/08 9/30/98 3/13/08 9/27/06 9/27/06 9/27/06 Catawba Units 1 and 2 Page 29 8/27/08

Page Number B 3.7.15-4 B 3.7.16-1 B 3.7.16-2 B 3.7.16-3 B 3.7.16-4 B 3.7.17-1 B 3.7.17-2 B 3.7.17-3 B 3.8. 1-1 B 3.8.1-2 B 3.8:1-3 B 3.8.1-4 B 3.8-1-5 B 3.8-1-6 B 3.8.1-7 B 3.8.1-8 B 3.8.1-9 B 3.8-1-10 B 3.8.1-11 B 3.8.1-12 B 3.8.1-13 B 3.8.1-14 B 3.8.1-15 B 3.8.1-16 B 3.8.1-17 B 3.8.1-18 B 3.8.1-19 B 3.8.1-20 B 3.8.1-21 B 3.8.1-22 B 3.8.1-23 B 3.8.1-24 Amendment Revision 0 Revision 2 Revision 2 Revision 2 Revision 0 Revision 1 Revision 1 Revision 1 Revision 1 Revision 0 Revision 1 Revision 2 Revision 2 Revision 2 Revision 2 Revision 1 Revision 1 Revision 1 Revision 0 Revision 0 Revision 1 Revision 0 Revision 0 Revision 0.

Revision 0 Revision 1 Revision 1 Revision 0 Revision 0 Re vision 2 Revision 1 Revision 0 Revision Date 9/27/ 06 9/27/06 9/27/06 9/27/06 9/27/06 3/13/08 3/13/08 3/13/08 2/26/01 9/30/98 11/5/07 11/5/07 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 5/10/05 9/30/98 9/30/98 8/27/08 9/30/98 9/30/98 9/30/98 9/30/98 11/5/07 11/5/07 9/30/98 9/30/98 6/25/07 3/16/00 9/30/98 Catawba Units 1 and 2Pae38/70 Page 30 8/27/08

Page Number B 3.8.6-3 B 3.8.6-4 B 3.8.6-5 B 3.8.6-6 B 3.8.6-7 B 3.8.7-1 B 3.8.7-2 B 3.8.7-3 B 3.8.7-4 B 3.8.8-1 B 3.8.8-2 B 3.8.8-3 B 3.8.8-4 B 3.8.9-1 B 3.8.9-2 B 3.8.9-3 B 3.8.9-4 B 3.8.9-5 B 3.8.9-6 B 3.8.9-7 B 3.8.9-8 B 3.8.9-9 B 3.8.9-10 B 3.8. 10-1 B 3.8.10-2

-B 3.8.10-3 B 3.8.10-4 B 3.9. 1 -1 B 3.9.1-2 B 3.9.1-3 B 3.9.1-4 B 3.9.2-1 Amendment Revision 2 Revision 2 Revision 1 Revision 1 Revision 1 Revision 0 Revision 1 Revision 2 Revision 0 Revision 0 Revision 2 Revision 2 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 0 Revision 1 Revision 1 Revision 0 Revision 0 Revision 2 Revision 1 Revision 1 Revision 2 Revision 2 Revision 0 Revision 2 Revision Date 4/27/05 4/27/ 05 4/27/05 4/27/05 4/27/05 9/30/98 3/15/04 3/15/04 3/15/04 9/30/98 10/10/06 7/29/03 7/29/03 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 9/30/98 2/26/99 2/26/99 9/30/98 9/30/98 7/29/03 7/29/03 9/1/05 9/1/05 8/27/08 9/1/05 6/21/04 Catawba Units 1 and 2Pae38/70 Page 32 8/27/08

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)

Once the unit is in MODE 3, this surveillance is no longer required. If power is to be maintained < P-1 0 or < P-6 for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for periods > 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

SR 3.3.1.9 SR 3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 7.

The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION.

SR 3.3.1.10 A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology.

The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.

SR3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.1-1.

Catawba Units 1 and 2 B 3.3.1-47 Revision No. 2

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10, every 18 months. This SR is modified by two notes. Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP.

The CHANNEL CALIBRATION for the source range and intermediate range neutron detectors consists of obtaining the high voltage detector plateau and discriminator curves for source range, and the high voltage detector plateau for intermediate range, evaluating those curves, and comparing the curves to the manufacturer's data. Note 2 states that this Surveillance is not required for the NIS power range detectors for entry into MODE 2 or 1, and is not required for the NIS intermediate range detectors for entry into MODE 2, because the unit must be in at least MODE 2 to perform the test for the intermediate range detectors and MODE 1 for the power range detectors. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed on the 18 month Frequency.

W SR 3.3.1.12 SR 3.3.1.12 is the performance of a CHANNEL CALIBRATION, as described in SR 3:3.1.10, every 18 months.

The Frequency is justified by the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

SR 3.3.1.13 SR 3.3.1.13 is the performance of a COT of RTS interlocks every 18 months.

The Frequency is based on the known reliability of the interlocks and the multichannel redundancy available and has been shown to be acceptable through operating experience.

Catawba Units 1 and 2 B 3.3.1-48 Revision No. 0

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 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.

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. 2

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.

4 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. 1

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 letd*own, 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 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents 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.

Catawba Units 1 and 2 B 3.4.13-5 Revision No. 3

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 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. 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 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.

REFERENCES

1.

10 CFR 50, Appendix A, GDC 30.

2.

Regulatory Guide 1.45, May 1973.

3.

UFSAR,.Section 15.

4.

1-0--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. 5

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- 0

HSS B 3.6.8 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.8.4 This SR ensures that each HSS train responds properly to a containment pressure high-high actuation signal. The Surveillance verifies that each fan starts after a delay of >_ 8 minutes and _< 10 minutes. The Frequency of 92 days conforms with the testing requirements for similar ESF equipment and considers the known reliability of fan motors. and controls and the two train redundancy available.- Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES

1.

10 CFR 50.44.

2.

10 CFR 50, Appendix A, GDC 41, 42, and 43.

3.

Regulatory Guide 1.7, Revision 2.

4.

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

Catawba Units 1 and 2 B.3.6.8-5 Revision No. 1

HIS B 3.6.9 BASES SURVEILLANCE REQUIREMENTS (continued)

OPERABILITY. The allowance of one inoperable hydrogen ignitor is acceptable because, although one inoperable hydrogen ignitor in a region would compromise redundancy in that region, the containment regions

-are interconnected so that ignition in one region would cause burning to progress to the others (i.e., there is overlap in each hydrogen ignitor's effectiveness between regions). The Frequency of 92 days has been shown to be acceptable through operating experience.

SR 3.6.9.2 This SR confirms that the two inoperable hydrogen ignitors allowed by SR 3.6.9.1 (i.e., one in each train) are not in the same containment region*. The Frequency of 92 days is acceptable based on the Frequency of SR 3.6.9.1, which provides the information for performing this SR.

SR 3.6.9.3 A more detailed functional test is performed every 18 months to verify system OPERABILITY. Each ignitor is visually examined to ensure that it is clean and that the electrical circuitry is energized. All ignitors, including normally inaccessible ignitors, are visually checked for a glow to verify that they are energized. Additionally, the surface temperature of each ignitor is measured in calm, nonturbulent atmospheric conditions to be

> 1700°F to demonstrate that a temperature sufficient for ignition is achieved*. The 1700'F temperature is a surveillance requirement. "An Analysis of Hydrogen Control Measures at McGuire Nuclear Station" (Ref. 5) section 3.8 identifies that the required normal operation temperature is 1500'F. Therefore, based upon ignitor performance testing conducted at-Catawba, the surveillance requirement of 1700'F ensures that sufficient margin. is present for continued hydrogen ignition under degraded bus conditions. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown.that these components usually pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a.

reliability standpoint.

  • For Unit 2 Cycle 11 operation only, or until the next Unit 2 entry into MODE 5 which allows affected ignitor replacement, this SR is not applicable to each train's ignitor located beneath the reactor vessel missile shield.

Catawba Units 1 and 2 B 3.6.9-5 Revision No. 4

HIS B 3.6.9 BASES REFERENCES 1.

2.

.3.

4.

5.

10 CFR 50.44.

10 CFR 50, Appendix A, GDC 41.

UFSAR, Section 6.2.

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

An Analysis of Hydrogen Control Measures at McGuire Nuclear Station.

I Catawba Units 1 and 2 B 3.6.9-6 RevisiQn No. 2

ABFVES B 3.7.12 B 3.7 PLANT SYSTEMS B 3.7.12 Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)

BASES BACKGROUND The ABFVESnormally filters air exhausted from all potentially contaminated areas of the auxiliary building, which includes the Emergency Core Cooling System (ECCS) pump rooms and non safety portions of the auxiliary building. The ABFVES, in conjunction with other normally operating systems, also provides ventilation for these areas of the auxiliary building..

The ABFVES consists of two independent and redundant trains. Each train consists of a heater demister section and a filter unit section. The heater demister section consists of a prefilter/moisture separator (to remove entrained water droplets) and an electric heater (to reduce the relative humidity of air entering the filter' unit). The filter unit section consists of a prefilter, an upstream HEPA filter, an activated carbon adsorber (for.the removal of gaseous activity, principally iodines), a downstream HEPA, and a fan. The downstream HEPA filter is not credited in the accident analysis, but serves to collect carbon fines.

Ductwork, valves or dampers, and instrumentation also form part of the system. Following receipt of a safety injection (SI) signal, the system isolates non safety portions of the ABFVES and exhausts air only from the ECCS pump rooms.

The ABFVES is normally aligned to bypass the system HEPA filters and carbon adsorbers. During emergency operations, the ABFVES dampers are realigned to the filtered position, and fans are started to begin filtration. During emergency operations, the ABFVES dampers are realigned to isolate the non-safety portions of the system and only draw air from the ECCS pump rooms, as well as the Elevation 522 pipe chase, and Elevation 543 and 560 mechanical penetration rooms.

The ABFVES is discussed in the UFSAR, Sections 6.5, 9.4, 14.4, and 15.6 (Refs. 1, 2, 3, and 4, respectively) since it may be used for normal, as well as post accident, atmospheric cleanup functions. The heaters are not required for OPERABILITY, since the laboratory test of the carbon is performed at 95% relative humidity, but have been maintained in the system to provide additional margin (Ref. 9).

0 Catawba Units 1 and 2 B 3.7.12-1

. Revision No. 3

ABFVES B 3.7.12 BASES p

APPLICABLE The design basis of the ABFVES is established by the large break

-SAFETY ANALYSES LOCA. The system evaluation assumes a constant leak rate of 0.5 gpm in the ECCS pump rooms and a constant leak rate of 0.5 gpm outside the ECCS pump rooms throughout the accident. In such a case, the system limits radioactive release to within the 10 CFR 50.67 (Ref.: 6) limits. The analysis of the effects and consequences of a large break LOCA is presented in Reference 4:

The ABFVES satisfies Criterion 3 of 10 CFR 50.36 (Ref. 7).

Lco Two independent and redundant trains of the ABFVES are required to be OPERABLE to ensure that at least one is available, assuming that a single failure disables the other train coincident with a loss of offsite power. Total system failure could result in the atmospheric release from the ECCS pump rooms exceeding 10 CFR 50.67 limits in the event of a Design Basis Accident (DBA).

ABFVES is considered OPERABLE when the individual components necessary to maintain the ECCS pump rooms filtration are OPERABLE in both trains.

An ABFVES train is considered OPERABLE when its associated:

a.

Fan is OPERABLE;

b.

HEPA filters and carbon adsorbers are capable of performing their filtration functions; and

c.

Ductwork, valves, and dampers are OPERABLE and air circulation can be maintained.

The ABFVES fans power supply is provided by buses which are shared between the two units. If normal or emergency power to the ABFVES becomes inoperable, then the Required Actions of this LCO must be entered independently for each unit that is in the MODE of applicability of the LCO.

0 Catawba Units I and 2 B 3.7.12-2 Revision No. 2

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

According to Reference 7, with both DGs inoperable, operation may.

continue for a period that should not exceed 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

F. 1 The sequencer(s) is an essential support system to both the offsite circuit and the DG associated with a given ESF bus. Furthermore, the

.sequencer is on the primary success path for most major AC electrically powered safety systems powered from the associated ESF bus.

Therefore, loss of an ESF bus sequencer affects every major ESF.

system in the train. When a sequencer is inoperable, its associated unit and train related offsite circuit and DG must also be declared inoperable and their corresponding Conditions must also be entered. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining sequencer OPERABILITY. This time period also ensures that the probability of an accident (requiring sequencer OPERABILITY) occurring during periods when the sequencer is inoperable is minimal.

G.1 and G.2 If the inoperable AC electric power sources. cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to 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 required unit conditions from full power conditions in an orderly manner and without challenging plant systems.

Catawba Units 1 and 2 B 3.8.1-13 Revision No. 1

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

H.1 Condition H corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.

SURVEILLANCE REQUIREMENTS The AC sources are designed to permit inspection and testing of all important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, Appendix A, GDC 18 (Ref. 9).

Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3), Regulatory Guide 1.108 (Ref. 10), and Regulatory Guide 1.137 (Ref. 11), as addressed in the UFSAR.

Where the SRs discussed herein specify voltage and frequency tolerances, the following is applicable. The minimum steady state output voltage of 3740 V is 90% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90%

of name plate rating.

The specified maximum steady state output voltage of 4580 V is equal to the maximum operating voltage specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages.

The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to.-t 2% of the 60 Hz nominal frequency and are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).

Catawba Units 1 and 28 B 3.8.1-14 Revision No. 0

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