Text

Technical Specifications (TS) Manual
	ML051800634
Person / Time
Site:	Catawba
Issue date:	06/01/2005
From:	Keller L; Duke Energy Corp
To:	; Office of Nuclear Reactor Regulation
References
	Download: ML051800634 (50)
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Duke DUKE ENERGY CORPORATION ESiergy', Catawba Nuclear Station 4800 Concord Rd.

York, SC 29745 June 1, 2005 Re: Catawba Nuclear Station Technical Specifications (TS) Manual 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 Pgs 16,18, 22, 25, 26, 28, 29, 30 Pgs 16,18, 22, 25, 26, 28, 29, 30 Tab 3.3.1 Bases B 3.3.1 B 3.3.1-44 B 3.3.1 B 3.3.1-44 Tab 3.3.3 Bases B 3.3.3 B 3.3.3-4 B 3.3.3 B 3.3.3-4 Tab 3.4.13 Bases B 3.4.13 B 3.4.13-6 B 3.4.13 B 3.4.13-6 Tab 3.4.15 Bases B 3.4.15 B 3.4.15-6 B 3.4.15 B 3.4.15-6 Tab 3.6.9 Bases B 3.6.9 B 3.6.9-6 B 3.6.9 B 3.6.9-6 www.duke -energy.com k Iwo

Tab 3.6.12 Bases B 3.6.12-1 through B 3.6.12-11 B 3.6.12-1 through B 3.6.12-11 Tab 3.7.6 Bases B 3.7.6-1 through B 3.7.6-4 B 3.7.6-1 through B 3.7.6-3 Tab 3.7.7 Bases B 3.7.7 B 3.7.7-2 B 3.7.7 B 3.7.7-2 Tab 3.8.1 Bases B 3.8.1-5 through B 3.8.1-10 B 3.8.1-5 through B 3.8.1-10 Tab 3.8.2 Bases B 3.8.2-3 through B 3.8.2-6 B 3.8.2-3 through B 3.8.2-6 Tab 3.8.3 Bases B 3.8.3 B 3.8.3-8 B 3.8.3 B 3.8.3-8 I

If you have any questions concerning the contents of this Technical Specification update, contact Jill Ferguson at (803) 831-3938.

,A1 Lee A. Keller Manager, Regulatory Compliance

Page Number Amendment Revision Date B 3.3.1-19 Revision 0 9130/98 B 3.3.1-20 Revision 0 9130/98 B 3.3.1-21 Revision 0 9/30/98 B 3.3.1-22 Revision 0 9/30/98 B 3.3.1-23 Revision 0 9/30/98 B 3.3.1-24 Revision 0 9/30/98 B 3.3.1-25 Revision 0 9/30/98 B 3.3.1-26 Revision 0 9/30/98 B 3.3.1-27 Revision 0 9/30/98 B 3.3.1-28 Revision 0 9/30/98 B 3.3.1-29 Revision 0 9/30/98 B 3.3.1-30 Revision 1 8/13/99 B 3.3.1-31 Revision 1 8/13/99 B 3.3.1-32 Revision 0 9/30/98 B 3.3.1-33 Revision 0 9/30/98 B 3.3.1-34 Revision 0 9/30/98 B 3.3.1-35 Revision 1 7/29/03 B 3.3.1-36 Revision 1 7/29/03 B 3.3.1-37 Revision 0 9/30/98 B 3.3.1-38 Revision 0 9/30/98 B 3.3.1-39 Revision 0 9/30/98 B 3.3.1-40 Revision 0 9130198 B 3.3.1-41 Revision 0 9/30/98 B 3.3.1-42 Revision 1 5/10/05 I B 3.3.1-43 Revision 1 5/10/05 I B 3.3.1-44 Revision 0 9/30/98 B 3.3.1-45 Revision 1 2/18/02 B 3.3.1-46 Revision 1 2/18/02 B 3.3.1-47 Revision 0 9/30/98 B 3.3.1-48 Revision 0 9130/98 B 3.3.1-49 Revision I 11/24/04 B 3.3.1-50 Revision 1 4/22/02 Catawba Units I and 2 Page 16 5110/05

I a Page Number Amendment Revision Date B 3.3.2-32 Revision 1 8/13/99 B 3.3.2-33 Revision 1 9/10/03 B 3.3.2-34 Revision 0 9/30/98 B 3.3.2-35 Revision 0 9/30/98 B 3.3.2-36 Revision 1 9/10/03 B 3.3.2-37 Revision 1 9/10/03 B 3.3.2-38 Revision 1 9/10/03 B 3.3.2-39 Revision 1 9/10/03 B 3.3.2-40 Revision 2 9/10/03 B 3.3.2-41 Revision 3 4/1/04 B 3.3.2-42 Revision 3 4/1/04 B 3.3.2-43 Revision 1 9/10/03 B 3.3.2-44 Revision 1 9/10/03 B 3.3.2-45 Revision 1 9/10/03 B 3.3.2-46 Revision 1 9/10/03 B 3.3.2-47 Revision 2 9/10/03 B 3.3.2-48 Revision 1 9/10/03 B 3.3.2-49 Revision 0 9/10/03 B 3.3.3-1 Revision 0 9/30/98 B 3.3.3-2 Revision 0 9/30/98 B 3.3.3-3 Revision 0 9/30/98 B 3.3.3-4 Revision 1 5/10/05 I B 3.3.3-5 Revision 0 9/30/98 B 3.3.3-6 Revision 0 9/30/98 B 3.3.3-7 Revision 0 9/30/98 B 3.3.3-8 Revision I 3/01/05 B 3.3.3-9 Revision 0 9/30/98 B 3.3.3-10 Revision 1 5/19/00 B 3.3.3-11 Revision 0 9/30/98 B 3.3.3-12 Revision 2 3/01/05 B 3.3.3-13 Revision 0 9/30/98 B 3.3.3-14 Revision 2 3/01/05 B 3.3.3-15 Revision 1 3/01/05 Catawba Units I and 2 Page 18 5/10/05

Page Number Amendment Revislon Date B 3.4.13-4 Revision 1 1/13/05 B 3.4.13-5 Revision 3 1/13/05 B 3.4.13-6 Revision 3 5/10/05 B 3.4.14-1 Revision 0 9/30/98 B 3.4.14-2 Revision 1 2126/99 B 3.4.14-3 Revision 0 9/30/98 B 3.4.14-4 Revision 0 9/30/98 B 3.4.14-5 Revision 0 9/30/98 B 3.4.14-6 Revision I 2/26/99 B 3.4.15-1 Revision 0 9/30/98 B 3.4.15-2 Revision 0 9130/98 B 3.4.15-3 Revision 1 4129104 B 3.4.15-4 Revision 0 9/30/98 B 3.4.15-5 Revision 0 9/30198 B 3.4.15-6 Revision 2 5/10/05 B 3.4.16-1 Revision 0 9/30/98 B 3.4.16-2 Revision 0 9/30/98 B 3.4.16-3 Revision 1 4/29/04 B 3.4.16-4 Revision I 4/29/04 B 3.4.16-5 Revision I 1/28/03 B 3.4.16-6 Revision 0 1/28/03 B 3.4.17-1 Revision 0 9/30/98 B 3.4.17-2 Revision 0 9/30/98 B 3.4.17-3 Revision 1 5/19/00 B 3.4.18-1 Revision 0 1/13/05 B 3.4.18-2 Revision 0 1/13/05 B 3.4.18-3 Revision 0 1/13/05 B 3.4.18-4 Revision 0 1/13/05 B 3.4.18-5 Revision 0 1/13105 B 3.4.18-6 Revision 0 1/13/05 B 3.4.18-7 Revision 0 1/13/05 B 3.4.18-8 Revision 0 1113/05 B 3.5.1-1 Revision 0 9/30/98 Catawba Units 1 and 2 Page 22 5/10/05

Page Number Amendment Revislon Date B 3.6.6-2 Revision 0 9/30/98 B 3.6.6-3 Revision 0 9/30/98 B 3.6.6-4 Revision 0 9/30/98 B 3.6.6-5 Revision 0 9/30/98 B 3.6.6-6 Revision 2 4/26/00 B 3.6.6-7 Revision 1 4/26/00 B 3.6.7-1 Revision 0 9/30/98 B 3.6.7-2 Revision 0 9/30/98 B 3.6.7-3 Revision 1 4/29/04 B 3.6.7-4 Revision 1 4/29/04 B 3.6.7-5 Revision 0 9/30/98 B 3.6.8-1 Revision 1 4/26/00 B 3.6.8-2 Revision 0 9/30/98 B 3.6.8-3 Revision 2 3/01/05 B 3.6.8-4 Revision 2 4/29/04 B 3.6.8-5 Revision 0 9/30/98 B 3.6.9-1 Revision 1 5/05/00 B 3.6.9-2 Revision 2 3/01/05 B 3.6.9-3 Revision 1 5/05/00 B 3.6.9-4 Revision 1 5/05/00 B 3.6.9-5 Revision 3 5/10/05 I B 3.6.9-6 Revision 2 2/26/01 B 3.6.10-1 Revision 0 9/30/98 B 3.6.10-2 Revision 0 9/30/98 B 3.6.10-3 Revision 0 9/30/98 B 3.6.10-4 Revision 0 9/30/98 B 3.6.10-5 Revision 0 9/30/98 B 3.6.10-6 Revision 0 9/30/98 B 3.6.11-1 Revision 0 9/30/98 B 3.6.11-2 Revision 0 9/30/98 B 3.6.11-3 Revision 0 9/30/98 B 3.6.11-4 Revision I 2/26/99 B 3.6.11-5 Revision 2 2/26/99 Catawba Units I and 2 Page 25 5/10105

Page Number Amendment Revision Date B 3.6.12-1 Revision 3 5/10/05 B 3.6.12-2 Revision 2 5/10/05 B 3.6.12-3 Revision 3 5/10/05 B 3.6.12-4 Revision 3 5110/05 B 3.6.12-5 Revision 2 5/10/05 B 3.6.12-6 Revision 4 5/10/05 B 3.6.12-7 Revision 3 5/10/05 B 3.6.12-8 Revision 2 5/10/05 B 3.6.12-9 Revision 3 5/10/05 B 3.6.12-10 Revision 2 5/10/05 B 3.6.12-11 Revision I 5/10/05 B 3.6.13-1 Revision 0 9/30/98 B 3.6.13-2 Revision 0 9/30/98 B 3.6.13-3 Revision 0 9/30/98 B 3.6.13-4 Revision 0 9/30/98 B 3.6.13-5 Revision 0 9/30/98 B 3.6.13-6 Revision 0 9/30/98 B 3.6.13-7 Revision 0 9130/98 B 3.6.13-8 Revision 1 2/26/99 B 3.6.13-9 Revision 0 9/30/98 B 3.6.14-1 Revision 0 9/30/98 B 3.6.14-2 Revision 0 9/30/98 B 3.6.14-3 Revision 0 9/30/98 B 3.6.14-4 Revision 0 9/30/98 B 3.6.14-5 Revision 0 9/30/98 B 3.6.14-6 Revision 0 9/30/98 B 3.6.15-1 Revision 0 9/30/98 B 3.6.15-2 Revision 0 9/30/98 B 3.6.15-3 Revision 0 9/30/98 B 3.6.15-4 Revision 0 9/30/98 B 3.6.16-1 Revision 1 4/09/99 B 3.6.16-2 Revision 1 4/09/99 B 3.6.16-3 Revision 1 4/09/99 Catawba Units 1 and 2 Page 26 5/10/05

Page Number Amendment Revision Date B 3.7.5-9 Revision I 4/29/04 B 3.7.6-1 Revision 2 5/10/05 I B 3.7.6-2 Revision I 5/10/05 B 3.7.6-3 Revision I 5/10/05 B 3.7.6-4 Revision 0 9/30/98 B 3.7.7-1 Revision 1 5/10/05 B 3.7.7-2 Revision 0 9/30/98 B 3.7.7-3 Revision 0 9/30/98 B 3.7.7-4 Revision 0 9/30/98 B 3.7.7-5 Revision 0 9/30/98 B 3.7.8-1 Revision 0 9/30/98 B 3.7.8-2 Revision 0 9/30/98 B 3.7.8-3 Revision 1 2/26/99 B 3.7.8-4 Revision 1 2/26/99 B 3.7.8-5 Revision 1 2/26/99 B 3.7.9-1 Revision I 2/26/99 B 3.7.9-2 Revision 1 2/26/99 B 3.7.9-3 Revision 0 9/30/98 B 3.7.9-4 Revision 0 9/30/98 B 3.7.10-1 Revision I 6/28/01 B 3.7.10-2 Revision 2 6/28/01 B 3.7.10-3 Revision 4 4/23/02 B 3.7.10-4 Revision 3 4/23/02 B 3.7.10-5 Revision 4 4/23/02 B 3.7.10-6 Revision 2 6/28/01 B 3.7.10-7 Revision 2 4/23/02 B 3.7.11-1 Revision 0 9/30/98

- 3.7.11-2 Revision 1 4/23/02 B 3.7.11-3 Revision 1 4/23/02 B 3.7.11-4 Revision I 4/23/02 B 3.7.12-1 Revision 1 2/26/99 B 3.7.12-2 Revision I 2/26/99 B 3.7.12-3 Revision 1 9/05/00 Catawba Units 1 and 2 Page 28 5/10/05

Page Number Amendment Revision Date B 3.7.12-4 Revision 1 9/05/00 B 3.7.12-5 Revision 1 9/05/00 B 3.7.12-6 Revision 0 9/05/00 B 3.7.13-1 Revision 2 4/23/02 B 3.7.13-2 Revision 2 4/23/02 B 3.7.13-3 Revision I 4/23/02 B 3.7.13-4 Revision I 3/26/99 B 3.7.13-5 Revision 1 4/23/02 B 3.7.14-1 Revision 0 9/30/98 B 3.7.14-2 Revision 0 9/30/98 B 3.7.14-3 Revision 0 9/30/98 B 3.7.15-1 Revision 0 9/30198 B 3.7.15-2 Revision 0 9/30/98 B 3.7.15-3 Revision 0 9/30/98 B 3.7.16-1 Revision 1 3/03/05 B 3.7.16-2 Revision 1 3/03/05 B 3.7.16-3 Revision 1 3/03/05 B 3.7.17-1 Revision 0 9/30/98 B 3.7.17-2 Revision 0 9/30/98 B 3.7.17-3 Revision 0 9/30/98 B 3.8.1-1 Revision 1 2/26/01 B 3.8.1-2 Revision 0 9/30/98 B 3.8.1-3 Revision 0 9/30/98 B 3.8.1-4 Revision 1 2/26/01 B 3.8.1-5 Revision 2 5/10/05 I B 3.8.1-6 Revision 2 5/10/05 I B 3.8.1-7 Revision 2 5/10/05 I B 3.8.1-8 Revision 1 5/10/05 I B 3.8.1-9 Revision 1 5/10/05 I B 3.8.1-10 Revision 1 5/10/05 I B 3.8.1-11 Revision 0 9/30/98 B 3.8.1-12 Revision 0 9/30/98 B 3.8.1-13 Revision 0 9/30/98 Catawba Units 1 and 2 Page 29 5/10/05

Page Number Amendment Revision Date B 3.8.1-12 Revision 0 9/30/98 B 3.8.1-13 Revision 0 9/30/98 B 3.8.1-14 Revision 0 9/30/98 B 3.8.1-15 Revision 0 9/30/98 B 3.8.1-16 Revision 0 9/30/98 B 3.8.1-17 Revision 0 9/30/98 B 3.8.1-18 Revision 0 9/30/98 B 3.8.1-19 Revision 0 9/30/98 B 3.8.1-20 Revision 0 9/30/98 B 3.8.1-21 Revision 0 9/30/98 B 3.8.1-22 Revision 1 3/16/00 B 3.8.1-23 Revision 1 '3/16/00 B 3.8.1-24 Revision 0 9/30/98 B 3.8.1-25 Revision 0 9/30/98 B 3.8.1-26 Revision 0 9/30/98 B 3.8.1-27 Revision 1 2/26/01 B 3.8.2-1 Revision 0 9/30/98 B 3.8.2-2 Revision 0 9/30/98 B 3.8.2-3 Revision 0 9/30/98 B 3.8.2-4 Revision I 5/10/05 I B 3.8.2-5 Revision 2 5/10/05 I B 3.8.2-6 Revision 1 5/10/05 I B 3.8.3-1 Revision 1 1/15/99 B 3.8.3-2 Revision 0 9/30/98 B 3.8.3-3 Revision 1 1/15/99 B 3.8.34 Revision 0 9/30/98 B 3.8.3-5 Revision 1 1/15/99 B 3.8.3-6 Revision 1 7/10/03 B 3.8.3-7 Revision I 7/10/03 B 3.8.3-8 Revision 2 5/10/05 I B 3.8.4-1 Revision 0 9/30/98 Catawba Units I and 2 Page 30 5/10/05

RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)

S.1 and S.2 Condition S applies to the P-7, P-8, P-9, and P-13 interlocks. With one or more channel(s) inoperable for one-out-of-two or two-out-of-four coincidence logic, the associated interlock must be verified to be in its required state for the existing unit condition within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or the unit must be placed in MODE 2 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . These actions are conservative for the case where power level is'being raised. Verifying the interlock status, by visual observation of the control room status lights, manually accomplishes the Interlock's Function. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is based on operating experience.and the minimum amount of time allowed for manual operator actioni. :The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 2 from full power in an'orderly manner and without challenging unit systems.

T.1 and T.2 Condition T applies to the RTB Undervoltage and Shunt Trip Mechanisms, or diverse trip features, in MODES 1 and 2. With one of the diverse trip features inoperable, it must be restored to an OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months or the unit must be placed in a MODE where the requirement'does not apply. This is accomplished by placing the unit in MODE 3 within the next 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (54 hours6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months total time). With both diverse trip features inoperable, the reacto trip breaker is inoperable and condition 0 is entered. The Completion Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is a reasonable time, based on operating experience, to reach MODE 3 from full power In an orderly manner and without challenging unit systems. With the unit in MODE 3, the MODES I and 2 requirement for this function Is no longer required and Condition C is entered. The affected RTB shall not be bypassed while one of the diverse features Is inoperable except for the time required to perforrm maintenance to one of the diverse features. The

.allowable'time for pertorming' maintenance of thediverse features is 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months forethe reasons stated under Condition 0.

The Completion Time of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months for Required Action T.1 is reasonable considering that in this Conditionrthere is one remaining diverse feature for the affected RTS, and one OPERABLE RTB capable of performing the safety function and given the low probability of an event occurring during this interval.

. N .

C~atawba Units 1-and 2 B 3.3.1-41 ~Revision No. 0

rD RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)

U.1 With two RTS trains inoperable, no automatic capability is available to shut down the reactor, and immediate plant shutdown in accordance with LCO 3.0.3 is required.

SURVEILLANCE The SRs for each RTS Function are identified by the SRs column of REQUIREMENTS Table 3.3.1-1 for that Function.

A Note has been added to the SR Table stating that Table 3.3.1-1 determines which SRs apply to which RTS Functions.

Note that each channel of process protection supplies both trains of the RTS. When testing Channel I, Train A and Train B must be examined.

Similarly, Train A and Train B must be examined when testing Channel II, Channel l1l, and Channel IV (if applicable). The CHANNEL CALIBRATION and COTs are performed in a manner that is consistent with the assumptions used in analytically calculating the required channel accuracies.

Performing the Neutron Flux Instrumentation surveillances meets the License Renewal Commitments for License Renewal Program for High-Range Radiation and Neutron Flux Instrumentation Circuits per UFSAR Chapter 18, Table 18-1 and License Renewal Commitments specification CNS-1 274.00-00-0016.

SR 3.3.1.1 Performance of the CHANNEL CHECK once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months ensures that gross failure of instrumentation has not occurred. A CHANNEL CHECK is horrhally a comparison of the parameter indicated on one channel to a similar parameter on other chan'hels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the sarne value. Significant deviations between the two instrument chanffiels could be an indication of excessive instrument drift in bne of the channels or of sotnething"even more serious. A CHANNEL CHECK'will detect g~is channel failure; thus, it is key to verifying that the instrumentation continues to operate properlybetween each CHANNEL CALIBRATION.

Agreement criteria are determined by the unit staff based on a combination of the channel instrument uncertainties, including indication Catawba Units 1 and 2 B 3.3.1-42 Revision No. 1

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit.'

The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of

'the displays associated with the LCO required channels.

SR 3.3.1.2 SR 3.3.1.2 compares the calorimetric heat balance calculation to the NIS channe6l output every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If the calorimetric exceeds the NIS channel output by > 2% RTP, the NIS is not declared inoperable, but must be adjusted. If the NIS channel output cannot be properly adjusted, the channel is declared inoperable.

Two Notes modify SR 3.3.1.2. The first Note indicates that the NIS channel output shall be adjusted consistent with the calorimetric results if the absolute difference between the NIS channel output and the calorimetric is > 2% RTP. The second Note clarifies that this Surveillance is required only if reactor power is 2 15% RTP and that 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is allowed for completing the first Surveillance after reaching 15% RTP. At lower power levels, calorimetric data are inaccurate.

'The Frequency of every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is adequate. It is based on unit operating experience, considering instrument reliability and operating

' history data for instrument drift. Together these factors demonstrate the change in the absolute difference between NIS and heat balance

- calculated powers rarely exceeds 2% in any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period. Maintaining the 2% agreement is only applicable during equilibrium conditions.

In addition, control room operators periodically monitor redundant indications and alarms to detect deviations in channel outputs.

SR 3.3.1.3 SR 3.3.1.3 compares tHincore sys'tem to the NIS channel output every 31 EFPD. If the absolute difference is 2 3%, the NIS channel is still OPERABLE, but must be readjusted.

Catawba'Units 1 and 2 B 3.3.1-43 Revision No. 1

RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)

If the NIS channel cannot be properly readjusted, the channel is declared inoperable. This Surveillance is perfonned to verify the f(AI) input to the overtemperature AT Function and overpower AT Function.

Two Notes modify SR 3.3.1.3. Note 1 indicates that the excore NIS channel shall be adjusted if the absolute difference between the incore and excore AFD is 2 3%. Note 2 clarifies that the Surveillance is required only if reactor power is > 15% RTP and that 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed for completing the first Surveillance after reaching 15% RTP.

The Frequency of every 31 EFPD is adequate. It is based on unit operating experience, considering instrument reliability and operating history data for instrument drift. Also, the slow changes in neutron flux during the fuel cycle can be detected during this interval.

SR 3.3.1.4 SR 3.3.1.4 is the performance of a TADOT every 31 days on a STAGGERED TEST BASIS. This test shall verify OPERABILITY by actuation of the end devices.

The RTB test shall include separate verification of the undervoltage and shunt trip mechanisms. Independent verification of RTB undervoltage and shunt trip Function is not required for the bypass breakers. No capability is provided for performing such a test at power. The independent test for bypass breakers is included in SR 3.3.1.14. The bypass breaker test shall include a local shunt trip. A Note has been added to indicate that this test must be performed on the bypass breaker prior to placing it in service.

The Frequency of every 31 days on a STAGGERED TEST BASIS is adequate. It is based on industry operating experience, considering instrument reliability and operating history data.

SR 3.3.1.5 SR 3.3.1.5 is the performance of an ACTUATION LOGIC TEST. The SSPS is tested every 31 days on a STAGGERED TEST BASIS, using the semiautomatic tester. The train being tested is placed in the bypass Catawba Units 1 and 2 B 3.3.1-44 Revision No. 0

PAM Instrumentation B 3.3.3 BASES APPLICABLE SAFETY ANALYSES (continued)

Determine if a gross breach of a barrier has occurred; and

. Initiate action necessary to protect the public and to estimate the magnitude of any impending threat.

PAM instrumentation that meets the definition of Type A in Regulatory Guide 1.97 satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4). Category I, non-Type A, instrumentation must be retained in TS because it is Iintended to assist operators in minimizing the consequences of accidents. Therefore, Category I, non-Type A, variables are Important for reducing public risk. -

LCO The PAM instrumentation LCO provides OPERABILITY requirements for Regulatory Guide 1.97 Type A monitors, which provide information required by the control room operators to perform certain manual actions specified in the unit Emergency Operating' Procedures. These manual actions ensure that a system can accomplish its safety function, and are credited in the safety analyses. Additionally, this LCO addresses Regulatory Guide 1.97 instruments that have been'designated Category I, non-Type A.

The OPERABILITY of the PAM instrumentation ensures there is sufficient information available on selected unit parameters to rjonitor and assess unit status following an accident. This capability is consistent with the recommendations of Refere'nce i.

LCO 3.3.3 requires two OPERABLE channels for most Functions. Two

- :-OPERABLE channels ensure no single failure'prevents operators from

- getting the information necessary for them to determine the safety status of the unit, and to bring the unit to and mnaintain it in a safe condition following an accident.,

Furthermore, OPERABILITY of two channels allows a CHANNEL CHECK

- during the post accident phase to'confirmthe validity of displayed Information..

In some cases, the total number of channels exceeds the number of

-required channels, e.g., pressurizer level has a total of three Catawba Units 1 and 2 B 3.3.3-3 Revision No. 0

PAM Instrumentation B 3.3.3 BASES LCO (continued) channels, however only two channels are required OPERABLE. This provides additional redundancy beyond that required by this LCO, i.e.,

when one channel of pressurizer level is inoperable, the required number of two channels can still be met. The ACTIONS of this LCO are only entered when the required number of channels cannot be met.

Type A and Category I variables are required to meet Regulatory Guide 1.97 Category I (Ref. 2) design and qualification requirements for seismic and environmental qualification, single failure criterion, utilization of emergency standby power, immediately accessible display, continuous readout, and recording of display.

Performing the Neutron Flux Instrumentation and Containment Area Radiation (High-Range) surveillances meets the License Renewal Commitments for License Renewal Program for High-Range Radiation and Neutron Flux Instrumentation Circuits per UFSAR Chapter 18, Table 18-1 and License Renewal Commitments specification CNS-1274.00 0016.

Listed below are discussions of the specified instrument Functions listed in Table 3.3.3-1.

1, 2. Reactor Coolant System (RCS) Hot and Cold Lea Temperatures RCS Hot and Cold Leg Temperatures are Category I variables provided for verification of core cooling and long term surveillance.

RCS hot and cold leg temperatures are used to determine RCS subcooling margin. RCS subcooling margin will allow termination of safety injection (SI); if still in progress, or reinitiation of SI if it has been stopped. RCS subcooling margin is also used for unit stabilization and cooidown control.

In addition, RCS cold leg temperature is used in conjunction with RCS hot leg temperature to verify the unit conditions necessary to establish natural circulation in the RCS.

Reactor coolant hot and cold leg temperature inputs are provided by a fast response resistance element in each loop.

RCS Hot and Cold Leg Temperature are diverse indications of RCS temperature. Core exit thermocouples also provide diverse indication of RCS temperature.

Catawba Units 1 and 2 B 3.3.34 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. Forthis SR, the volumetric calculation of un'identfied 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 I indicates that this SR Is not required to be completed untIl 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months of steady state operation near operating pressure have beeh established.

Steady state operation Is'required to perform 'a proper Inventory balance; calculations during maneuvering are not useful and Note I requires the Surveillance to be met when steady state Isestablished. 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 Isprovided 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is a reasonable Interval to trend LEAKAGE and recognizes the Importance of early leakage detection Inthe prevention of

-accidents and reduction of potential 6cnsequences. A Note under the Frequency column states that this SR Is only required to be performed during steady state operation.

Catawba Units I 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, 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 requiredto be completed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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. 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.

Catawba Units 1 and 2 B 3.4.13-6 Revision No. 3

RCS Leakage Detection Instrumentation i* B 3.4.15 BASES ACTIONS (continued)

D.1 and D.2 With the required containment atmosphere radioactivity monitor and the required containment ventilation unit condensate'drain tank level monitor Inoperable, the only means of detecting leakage Is'the containment floor and equipment sump level monitor. This Condition does not provide the required diverse means of leakage detection. The Required Action is to restore either-of the inoperable required monitors to OPERABLE status within 30 days to regain the Intended leakage detection diversity. The 30 day Completion Time ensures that the plant will 'not be operated in a reduced configuration for a lengthy time period.

E.1 and E.2 If a Required Action of Condition A, B, C, or D cannot be met, the plant must be brought to a MODE in which the requirement does not apply. To achieve this status, the plant must be brought to at least MODE 3 within

6 hours and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .' The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions Inan orderly manner and without challenging plant systems.

F.1 With all required monitors Inoperable, no automatic means of monitoring leakage are available, and immediate plant shutdown in accordance with LCO 3.0.3 is required.

SURVEILLANCE SR 3.4.15.1 REQUIREMENTS SR 3.4.15.1 requires the performance of a CHANNEL CHECK of the required containment atmosphere radioactivity monitor. The check gives reasonable confidence that the channel is operating properly. The

-Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is based on instrument reliability and is reasonable for detecting off normal conditions.

Catawba Units 1 and 2 'B 3.4.15-5 Revision No. 0

RCS Leakage Detection Instrumentalion B 3.4.15 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.15.2 SR 3.4.15.2 requires the performance of a COT on the required containment atmosphere radioactivity monitor. The test ensures that the monitor can perform its function in the desired manner. The test verifies the alarm setpoint and relative accuracy of the instrument string. The COT is relative to the detection of radioactivity indicative of a 1 gpm RCS leak, within one hour of leakage onset. The COT does not verify automatic actions associated with high radioactivity on the applicable channels. The Frequency of 92 days considers instrument reliability, and operating experience has shown that it is proper for detecting degradation.

SR 3.4.15.3. SR 3.4.15.4, and SR 3.4.15.5 These SRs require the performance of a CHANNEL CALIBRATION for each of the RCS leakage detection instrumentation channels. The calibration verifies the accuracy of the instrument string, including the instruments located inside containment. The Frequency of 18 months is a typical refueling cycle and considers channel reliability. Again, operating experience has proven that this Frequency is acceptable.

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

2. Regulatory Guide 1.45.

3. UFSAR, Section 5.2.5.

4. 10 CFR 50 3fs Technical Specifications, (c)(2)(ii).

5. UFSAR, Table 18-1.

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

Catawba Units 1 and 2 B 3.4.15fi Revision No. 2

, 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 expenence.

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 to be Ž17000 F to demonstrate that a temperature sufficient for ignition is achieved*. The 1700OF 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 15000F. Therefore, based upon ignitor parformance testing conducted at Catawba, the surveillance requirement of 1700OF 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. 3

, HIS B 3.6.9 BASES REFERENCES 1. 10 CFR 50.44.

2. 10 CFR 50, Appendix A, GDC 41.

3. UFSAR, Section 6.2.

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

5. An Analysis of Hydrogen Control Measures at McGuire Nuclear Station. I Catawba Units 1 and 2 B 3.6.9-6 Revision No. 2

Ice Bed B 3.6.12 B 3.6 CONTAINMENT SYSTEMS B 3.6X12 Ice Bed BASES -

BACKGROUND The ice bed con'sists'of a minimum of 2,132,000 lbs of ice stored within the ice' condenser. 'The primary purpose of the Ice bed is to provide a large heat'sink in the event of a release of energy from a Design Basis

' Accident (DBA) in'containment. The ice would absorb energy and limit containment peak pressure and temperature, during the accident

- transient. Limiting the pressure and temperature reduces the release of fission product radioactivity from containment to the environment in the event of a'DBA.'

The ice condenser is an'annular compartment enclosing approximately 3000 of the perimeter of the upper containment compartment, but penetrating the operating deck so that a portion extends into the lower containment compartment. The lower portion has a series of hinged doors exposed to the atmosphere of the lower containment compartment, which, for normal unit operation, are designed to remain closed. At the top of the ice condenser is 'another set of doors exposed to the atmosphere of the upper compartment, which also remain closed during normal unit operation. Intermediate deck doors, located below the top deck doors, form the floor of a plenum at the, upper part of the ice condenser.' These doors also remain closed during normal unit operation. 'The upper plenum area is used to facilitate surveillance and maintenance of the ice bed..

The ice baskets contain'the ice within the ice condenser. The ice bed is considered'to consist of the total voluine frorfrth-bottom elevation cif-the ice baskets to the top elevation of the ice baskets. 'The ice baskets position'the ice within the ice bed in an arrangement to promote heat transfer from steam to ice.' This arrangement enhances the ice condenser's primary function of condensing steam and absorbing heat energy released to the containment during a DBA.'

In'the event of a DBA, the ice condenser inlet doors (located below the operating deck) open due to the pressure rise in the lower compartment.

This allows air and steam to flow from the tower compartment into the ice condenser. The resulting pressure increase within'the ice condenser causes the intermediate deck doors and the top deck doors to open, which allows the air to flow out of the ice condenser into the upper compartment. Steam condensation within the ice condenser limits the Catawba Units 1 and 2 B 3.6.12-1 ' Revision No. 3

Ice Bed B 3.6.12 BASES BACKGROUND (continued) pressure and temperature buildup in containment. A divider barrier (i.e.,

operating deck and extensions thereof) separates the upper and lower compartments and ensures that the steam is directed into the ice condenser.

The ice, together with the containment spray, is adequate to absorb the initial blowdown of steam and water from a DBA and the additional heat loads that would enter containment during several hours following the initial blowdown. The additional heat loads would come from the residual heat in the'reactor core, the hot piping and components, and the secondary system, including the steam generators. During the post blowdown period, the Air Return System (ARS) returns upper compartment air through the divider barrier to the lower compartment.

This serves to equalize pressures in containment and to continue circulating heated air and steam from the lower compartment through the ice condenser where the heat is removed by the remaining ice.

As ice melts, the water passes through the ice condenser floor drains into the lower compartment. Thus, a second function of the ice bed is to be a large source of borated water (via the containment sump) for long term Emergency Core Cooling System (ECCS) and Containment Spray System heat removal functions in the recirculation mode.

A third function of the ice bed and melted ice is to remove fission product iodine that may be released from the core during a DBA. Iodine removal occurs during the ice melt phase of the accident and continues as the melted ice is sprayed into the containment atmosphere by the Containment Spray System. The ice is adjusted to an alkaline pH that facilitates removal of radioactive iodine from the containment

--. atmosphere. The alkaline pH also minimizes the occurrence of tih chloride and caustic stress corrosion on mechanical systems and components exposed to ECCS and Containment Spray System fluids in the recirculation mode of operation.

it is important for ice to exist inthe ice baskets, the ice to be appropriately distributed around the 24 ice condenser bays, and for open flow paths to exist around ice baskets. This is especially important during the initial blowdown so that the steam and water mixture entering the lower compartment do not pass through only part of the ice condenser, depleting the ice there while bypassing the ice in other bays.

Catawba Units I and 2 B 3.6.12-2 Revision No. 2

Ice Bed B 3.6.12 BASES BACKGROUND (continued)

-Two phenomena that can degrade the ice bed during the long service period are:

a. Loss of ice by melting or sublimation; and

b. Obstruction of flow passages through the ice bed due to buildup of ice.

Both of these degrading phenomena are reduced by minimizing air leakage into and out of the ice condenser.

The ice bed limits the temperature and pressure that could be expected following a DBA, thus limiting leakage of fission product radioactivity from containment to the environment..

APPLICABLE The limiting DBAs considered relative to containment temperature SAFETY ANALYSES and pressure are the loss of coolant accident (LOCA)' and the steam line break (SLB). The LOCA and SLB are analyzed using computer codes designed to predict the resultant containment pressure and temperature transients. DBAs are not assumed to occur simultaneously or consecutively.

Although the ice condenser is a passive system that requires no electrical power to perform its function, the Containment Spray System, RHR Spray System, and the ARS also function to assist the ice bed in limiting pressures and temperatures. Therefore, the postulated DBAs are analyzed in regards to containment Engineered Safety Feature (ESF) systenrs, assuming the loss of one ESF bus,-which is the worst case single active failure and results in one train each of the Containment Spray System, RHR Spray System, and ARS being inoperable.

The limiting DBA analyses (Ref. 1) show that the maximum peak containment pressure results from the LOCA analysis and is calculated to be less than' the containment design pressure. For certain aspects of the transient accident analyses, maximizing the calculated containment pressure is not conservative. In particular, the cooling effectiveness of the ECCS durig' the core reflood phase of a LOCA analysis increases with increasing containment backpressure. For these calculations, the containment backpressure is calculated in a manner designed to Catawba Units 1 and 2 B B 3.6.12 . ... I Revision No. 3

Ice Bed B 3.6.12 BASES APPLICABLE SAFETY ANALYSES (continued) conservatively minimize, rather than maximize, the calculated transient containment pressures, in accordance with 10 CFR 50, Appendix K (Ref. 2).

The maximum peak containment atmosphere temperature results from the SLB analysis and is discussed in the Bases for LCO 3.6.5, "Containment Air Temperature."

In addition to calculating the overall peak containment pressures, the DBA analyses include calculation of the transient differential pressures that occur across subcompartment walls during the initial blowdown phase of the accident transient. The internal containment walls and structures are designed to withstand these local transient pressure differentials for the limiting DBAs.

The ice bed satisfies Criterion 3 of 10 CFR 50.36 (Ref. 3).

LCO The ice bed LCO requires the existence of the required quantity of stored ice, appropriate distribution of the ice and the ice bed, open flow paths through the ice bed, and appropriate chemical content and pH of the stored ice. The stored ice functions to absorb heat during the blowdown phase and long term phase of a DBA, thereby limiting containment air temperature and pressure. The chemical content and pH of the stored ice provide core SDM (boron content) and remove radioactive iodine from the containment atmosphere when the melted ice is recirculated through the ECCS and the Containment Spray System, respectively. The limits on boron concentration and pH of the ice are associated with containment sump pH ranging between 7.5 and 9.3 inclusive following the design basis LOCA. -a APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause an increase in containment pressure and temperature requiring the operation of the ice bed.

Therefore, the LCO is applicable in MODES 1, 2, 3, and 4.

In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the ice bed is not required to be OPERABLE in these MODES.

Catawba Units 1 and 2 B 3.6.12-4 Revision No. 3

I Ice Bed B 3.6.12 BASES ACTIONS A.1 If the ice bed is inoperable, it must be restored to OPERABLE status within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months . The Completion Time was developed based on operating experience, which confirms that due to the very large mass of stored ice, the parameters comprising OPERABILITY do not change appreciably in this time period. Because of this fact, the Surveillance Frequencies are long (months), except for the ice bed temperature, which is checked every 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months s: If a degraded condition is identified, even for temperature, with such a large mass of ice it is not possible for the degraded condition to significantly degrade further in a 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months period.

Therefore, 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is a reasonable amount of time to correct a degraded condition before initiating a shutdown.

B.1 and B.2 If the ice bed cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.12.1 REQUIREMENTS Verifying that the maximum temperature of the ice bed is

270 F ensures that the ice is kept well below.the melting point. ".The'l2 hour Frequency was based on operating experience, which confirmed that, due to the large mass of stored ice, it is not possible for the ice bed temperatuie to degrade significantly within a'12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months period and was also based on assessing the proximity of the LCO limit to the melting temperature.

Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of indications in the control room, including the alarm, to alert the operator to an abnormal ice bed temperature condition. This SR may be satisfied by use of the Ice Bed Temperature Monitoring System.

Catawba Units I and 2 B 3.6.12-5 .'_: -: Revisioni No.2

Ice Bed B 3.6.12 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.12.2 This SR ensures that initial ice fill and any subsequent ice additions meet the boron concentration and pH requirements of SR 3.6.12.7. The SR is modified by a NOTE that allows the chemical analysis to be performed on either the liquid or resulting ice of each sodium tetraborate solution prepared. If ice is obtained from offsite sources, then chemical analysis data must be obtained for the ice supplied.

SR 3.6.12.3 This SR ensures that the air/steam flow channels through the ice bed have not accumulated ice blockage that exceeds 15 percent of the total flow area through the ice bed region. The allowable 15 percent buildup of ice is based on the analysis of the sub-compartment response to a design basis LOCA with partial blockage of the ice condenser flow channels. The analysis did not perform detailed flow area modeling, but rather lumped the ice condenser bays into six sections ranging from 2.75 bays to 6.5 bays. Individual bays are acceptable with greater than 15 percent blockage, as long as 15 percent blockage is not exceeded for any analysis section.

To provide a 95 percent confidence that flow blockage does not exceed the allowed 15 percent, the visual inspection must be made for at least 54 (33 percent) of the 162 flow channels per ice condenser bay. The visual inspection of the ice bed flow channels is to inspect the flow area, by looking down from the top of the ice bed, and where view is achievable up from the bottom of the ice bed. Flow channels to be inspected are determiriWd by random- sample. As the most restrictive ice bed flow passage is found at a lattice frame elevation, the 15 percent blockage criteria only applies to "flow channels" that comprise the area:

a. between ice baskets, and

b. past lattice frames and wall panels.

Due to a significantly larger flow area in the regions of the upper deck grating and the lower inlet plenum support structures and turning vanes, it would require a gross buildup of ice on these structures to obtain a degradation in air/steam flow. Therefore, these structures are excluded as part of a flow channel for application of the 15 percent blockage criteria. Plant and industry experience have shown that removal of ice from the excluded structures during the refueling outage is sufficient to Catawba Units I and 2 B 3.6.12-6 Revision No. 4

i Ice Bed B 3.6.12 BASES SURVEILLANCE REQUIREMENTS (continued)

ensure they remain operable throughout the operating cycle. Thus, removal of any gross ice buildup on the excluded structures is performed following outage maintenance activities.

Operating experience has demonstrated that the ice bed is the region that is the most flow restrictive, due to the normal presence of ice accumulation on lattice frames and wall panels. The flow area through the ice basket support platform is not a more restrictive flow area because it is easily accessible from the lower,plenum and is maintained clear of ice accumulation. -There is not a mechanistically credible method for ice to accumulate on the ice basket support platform during plant operation.

Plant and industry experience has shown that the vertical flow area through the ice basket support platform remains clear of ice accumulation that could produce blockage. Normally only a glaze may develop or exist on the ice basket support platform which is not significant to blockage of flow area. Additionally, outage maintenance practices provide measures to clear the ice basket support platform following maintenance activities of any accumulation of ice that could block flow areas.

Activities that have a potential for significant degradation of flow channels should be limited to outage periods. Performance of this SR following completion of these activities assures the ice bed is in an acceptable condition for the duration of the operating cycle.

Frost buildup or loose ice is not to be considered as flow channel blockage, whereas attached ice is considered blockage of a flow channel.

Frost is the solid form of water that is loosely adherent, and can be brushed off with the open hand. ..-.

SR 3.6.12.4 Ice mass determination methodology is designed to verify the total as-found (pre-maintenance) mass of ice in the ice bed, and the appropriate

. distribution of that mass, using a random sampling of individual baskets.

The random sample will include at least 30 baskets from each of three defined Radial Zones (at least 90 baskets total). Radial Zone A consists of baskets located in rows 8, and 9 (innermost rows adjacent to the Crane Wall), Radial Zone B consists of baskets located in rows 4, 5, 6,

.and 7 (middle rows of the ice bed), and Radial Zone C consists of x baskets located in rows 1, 2, and 3 (outermost rows adjacent to the Containment Vessel)..

Catawba Units I and 23 B 3.6.12-7 Revision No. 31

Ice Bed B 3.6.12 BASES SURVEILLANCE REQUIREMENTS (continued)

The Radial Zones chosen include the row groupings nearest the inside and outside walls of the ice bed and the middle rows of the ice bed.

These groupings facilitate the statistical sampling plan by creating sub-populations of ice baskets that have similar mean mass and sublimation characteristics.

Methodology for determining sample ice basket mass will be either by direct lifting or by alternative techniques. Any method chosen will include procedural allowances for the accuracy of the method used. The number of sample baskets in any Radial Zone may be increased once by adding 20 or more randomly selected baskets to verify the total mass of that Radial Zone.

In the event the mass of a selected basket in a sample population (initial or expanded) cannot be determined by any available means (e.g., due to surface ice accumulation or obstruction), a randomly selected representative alternate basket may be used to replace the original selection in that sample population. If employed, the representative alternate must meet the following criteria:

a. Alternate selection must be from the same bay-Zone (i.e., same bay, same Radial Zone) as the original selection, and

b. Alternate selection cannot be a repeated selection (original or alternate) in the current Surveillance, and cannot have been used as an analyzed alternate selection in the three most recent Surveillances.

The complete basis for the methodology used in establishing the 95%

confidence level in the total ice bed mass is documented in Ref. 5.

The total ice mass and individual Radial Zone ice mass requirements defined in this Surveillance, and the minimum ice mass per basket requirement defined by SR 3.6.12.5, are the minimum requirements for OPERABILITY. Additional ice mass beyond the SRs is maintained to address sublimation. This sublimation allowance is generally applied to baskets in each Radial Zone, as appropriate, at the beginning of an operating cycle to ensure sufficient ice is available at the end of the operating cycle for the ice condenser to perform its intended design function.

The Frequency of 18 months was based on ice storage tests, and the typical sublimation allowance maintained in the ice mass over and above the minimum ice mass assumed in the safety analyses. Operating and Catawba Units I and 2 B 3.6.12-8 Revision No. 2

Ice Bed B 3.6.12 BASES SURVEILLANCE REQUIREMENTS (continued) maintenance experience has verified that, with the 18 month Frequency, the minimum mass and distribution requirements in the ice bed are maintained.

SR '3.6.12.5 Verifying that each selected sample basket from SR 3.6.12.4 contains at least 600 lbs of ice in the as-found (pre-maintenance) condition ensures that a significant localized degraded mass condition is avoided.

This SR establishes a per basket limit to ensure any ice mass degradation is consistent with the initial conditions of the DBA by not significantly affecting the containment pressure response. Ref. 5 provides insights thr6ugh sensitivity runs that demonstrate that the containment peak pressure during a DBA is not significantly affected by the ice mass in a large localized region of baskets being degraded below the required safety analysis mean, when the Radial Zone and total ice mass requirements of SR 3.6.12.4 are satisfied. Any basket identified as containing less than 600 lbs of ice requires.appropriately entering the TS Required Action for an inoperable ice bed due to the potential that it may represent a significant condition adverse to quality.

As documented in Ref. 5, maintenance practices actively manage individual ice basket mass above the required safety analysis mean for each Radial"Zone. Specifically, each basket is serviced to keep its ice mass above 750 lbs for Radial Zone A, 1196 lbs for Radial Zone B, and 1196 lbs for Radial Zone C. If a basket sublimates below the safety analysis mean value, this instance is identified within the plant's correctiv'e action-prografn,'iincluding -!evahiating -maintenance practices to identify the cause'and correct any deficiencies. These maintenance practices provide defense' in depth beyond compliance with the ice bed surveillance requirements by limiting the occurrence of individual baskets

'with ice mass less than the required safety analysis mean.

SR 3.6.12.6 This SR ensures that a representative sampling of accessible portions of ice baskets, which'are relatively thin walled, perforated cylinders, have not been degraded by wear, cracks, corrosion, or other damage. The SR is designed around a full-lengthi inspection of a sample of baskets, and is intended to monitor the effect of the ice condenser environment on ice baskets. The groupings defined in the SR (two baskets in each Catawba Units I and 2 B 3.6.12-9 _- - Revision No. 3

- -I Ice Bed B 3.6.12 BASES SURVEILLANCE REQUIREMENTS (continued) azimuthal third of the ice bed) ensure that the sampling of baskets is reasonably distributed. The Frequency of 40 months for a visual inspection of the structural soundness of the ice baskets is based on engineering judgment and considers such factors as the thickness of the basket walls relative to corrosion rates expected in their service environment and the results of the long term ice storage testing.

SR 3.6.12.7 Verifying the chemical composition of the stored ice ensures that the stored ice has a boron concentration > 1800 ppm and < 2330 ppm as sodium tetraborate and a high pH, 2 9.0 and < 9.5 at 25 0C, in order to meet the requirement for borated water when the melted ice is used in the ECCS recirculation mode of operation. Additionally, the minimum boron concentration setpoint is used to assure reactor suboriticality in a post LOCA environment, while the maximum boron concentration is used as the bounding value in the hot leg switchover timing calculation (Ref.

4). This is accomplished by obtaining at least 24 ice samples. Each sample is taken approximately one foot from the top of the ice of each randomly selected ice basket in each ice condenser bay. The SR is modified by a NOTE that allows the boron concentration and pH value obtained from averaging the individual samples' analysis results to satisfy the requirements of the SR. If either the average boron concentration or average pH value is outside their prescribed limit, then entry into ACTION Condition A is required. Sodium tetraborate has been proven effective in maintaining the boron content for long storage periods, and it also enhances the ability of the solution to remove and retain fission product iodine. The high pH is required to enhance the effectiveness of the ice

.. -. t * ;

and the melted ice in removing iodine frorme do. aintainment atmosphere.

This pH range also minimizes the occurrence of chloride and caustic stress corrosion on mechanical systems and components exposed to ECCS and Containment Spray System fluids in the recirculation mode of operation. The Frequency of 54 months is intended to be consistent with the expected length of three fuel cycles, and was developed considering these facts:

a. Long term ice storage tests have determined that the chemical composition of the stored ice is extremely stable;

b. There are no normal operating mechanisms that significantly change the boron concentration of the stored ice, and pH remains within a 9.0 - 9.5 range when boron concentrations are above approximately 1200 ppm; and Catawba Units 1 and 2 B 3.6.12-1 0 Revision No. 2

Ice Bed B 3.6.12 BASES SURVEILLANCE REQUIREMENTS (continued)

c. Operating experience has demonstrated that meeting the boron concentration and pH requirements has not been a problem.

REFERENCES 1. UFSAR, Section 6.2.

2. 10 CFR 50, Appendix K.

3. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

4. UFSAR, Section 6.3.3.

5. Topical Report ICUG-001, Application of the Active Ice Mass Management Concept to the Ice Condenser Ice Mass Technical Specification, Revision 2.

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

7. Catawba License Renewal Commitments, CNS-1274.00-00-0016, Section 4.17.

Catawba Units 1 and 2 B 3.6.12-11 Revision No. 1

CSS B 3.7.6 B 3.7 PLANT SYSTEMS B 3.7.6 Condensate Storage System (CSS)

. BAS

.. . t BASES BACKGROUND The CSS provides a source of water to the steam generators for removing decay and sensible heat from' the Reactor Coolant System r (RCS). -The CSS provides a passive flow of water,' by gravity, to the F

Auxiliary.Feedwater (AFW) System (LCO 3.7.5). The steam produced is released to the atmosphere by the main steam safety valves, the steam generator PORVs, or to the turbine condenser. The CSS is formed from the Upper Surge Tanks (two 42,500 gallon tanks per unit), the Auxiliary Feedwater Condensate Storage Tank (one 42,500 gallon tank'per unit),

and the Condenser Hotwell (normal operating level of 170,000 gallons).

I The safety grade and seismically designed source of water for the Auxiliary AFW system, which serves as the ultimate long-term safety related source is the Standby Nuclear Service Water Pond. This required source is covered in LCO 3.7.9, "Standby Nuclear Service Water Pond_

(SNSWP)" and s 'short and long term water supply satisfies'all requirements for the AFW system except for Station Blackout (SBO) requirements.

When the'main steam ,isolation valves are open, the preferred means of heat removal is to discharge steam to the condenser by the nonsafety grade path of the steam dumps to the condenser valves. The condensed steam is'retured to the CSS by the condensate pump. This has the advantage'of conserving condensate while minimizing releases to the environment.

'A description of the CSS is found in the UFSAR, Section 10.4 (Ref. 1).

APPLICABLE - The SNSWP provides cooling water to remove decay heat and to SAFETY ANALYSES cool down the unit following all events in the accident analysis as discussed in the UFSAR, Chapters 6 and 15 (Refs. 2 and 3, respectively). Because of the water quality, the SNSWP is not used for the normal source of water to the AFW system. The SNSWP serves as a backup source to supply only when the CSS can not supply AFW.

I Catawba Units 1 and 2 B 3.7.6-1 s. tRevision No. 2

csS B 3.7.6 BASES LCO In order to satisfy recommendations made for the sizing of the system, the CSS contains sufficient cooling water to remove decay heat for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months following a reactor trip from 100% RTP, and then to cool down the RCS to RHR entry conditions, assuming a natural circulation cooldown.

In doing this, it must retain sufficient water to ensure adequate net positive suction head for the AFW pumps during cooldown. I The CSS level required is equivalent to a capacity > 225,000 gallons, which is based on holding the unit in MODE 3 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , followed by a 5 hour5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months cooldown to RHR entry conditions at 50 0F/hour. The OPERABILITY of the CSS is determined by maintaining the tanks' levels at or above the minimum required volume.

APPLICABILITY In MODES 1, 2, and 3, and in MODE 4, when steam generator is being relied upon for heat removal, the CSS is required to be OPERABLE.

In MODE 5 or 6, the CSS is not required because the AFW System is not required.

ACTIONS A.1 and A.2 If the OSS inventory is not within limits, the OPERABILITY of the assured supply should be verified by administrative means within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. The assured supply is considered the Nuclear Service Water System (NSWS) and ultimately the SNSWP.

OPERABILITY of the assured feedwater supply must include verification that the flow paths from the assured water supply to the AFW pumps are OPERABLE, and that the assured supply has the required volume of water available. The CSS must be restored to OPERABLE status within

, days, because the assured supply may be performing this function in addition to its normal functions. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to verify the OPERABILITY of the assured water supply. The 7 day Completion Time is reasonable, based on an OPERABLE assured water supply being available, and the low probability of an event occurring during this time period requiring the CSS.

.1 and B.2 If the CSS cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least Catawba Units 1 and 2 B 3.7.6-2 Revision No. 1

CSS B 3.7.6 BASES ACTIONS (continued)

MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4, without reliance on the steam generator for heat removal, within 18 hours2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months . 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 unit systems.

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS This SR verifies that the CSS contains the required inventory of cooling water. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is based on operating experience and the need for operator awareness of unit evolutions that may affect the CSS inventory between checks. Also, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications in the control room, including alarms, to alert the operator to abnormal deviations in the CSS level.

REFERENCES 1. UFSAR, Section 10.4.

2. UFSAR, Chapter 6.

3. UFSAR, Chapter 15.

I.

Catawba Units 1 and 2 B 3.7.6-3 Revision No. 1

CCW System B 3.7.7 B 3.7 PLANT SYSTEMS B 3.7.7 Component Cooling Water (CCW) System BASES BACKGROUND The CCW System provides a heat sink for the removal of process and

' 'operating heat from safety related components during a Design Basis Accident (DBA) or transient. During normal operation, the CCW System also provides this function forvarious nonessential components, as well as the spent fuel storage pool. The CCW System serves as a barrier to the release of radioactive byproducts between potentially radioactive systems and the NuclearService Water System (NSWS), and thus to the environment.

The CCW System is arranged as two independent, full capacity cooling loops, and has isolatable non'safety related components. Each safety related train includes two 50% capacity pumps, surge tank heat exchanger, piping, valves, and instrumentation. Each safety related train is powered from a separate'bus. An open surge tank in the system provides 'sufficient inventory to protect the pumps from a lack of net positive suction head available (NPSHA)'due to a moderate energy line break. The purips have sufficient NPSHA with the surge tank empty provided the piping up to the tank is filled. The pumps on each train are automatically'started on receipt of a safety injection signal, and all nonessential components are Isolated.

Additional information on the design and operation of the system, along with a list of the components served, is presented in the UFSAR, Section 9.2 (Ref. 1). The principal safety related function of the CCW Systenrr1' the Temoval do deba$bat from the reactor via the Residual Heat Removal (RHR) System. This may be during a normal or post accident cooldown'and shutdown.

APPLICABLE The safety related design basis function of the CCWSystem is to remove SAFETY ANALYSES waste heat from various components essential in mitigating design basis

' 'events which require Emergency Core Cooling System (ECCS) operation. The CCW Systemis 'also used to support normal operation.

TV normal temperature of the CCW Is 870F, and, during unit cooldown to MODE 5 (Tcow < 2000F), a maximum temperature of 1200 F is Catawba Units 1 and 2 B 3.7.7-1 Revision No. I

CCW System B 3.7.7 BASES APPLICABLE SAFETY ANALYSES (continued) assumed (Ref. 1). This 1200F limit is to prevent thermal degradation of the large pump motors supplied with cooling water from the CCW System.

The CCW System is designed to perform its function with a single failure of any active component, assuming a loss of offsite power.

The COW System also functions to cool the unit from RHR entry conditions (Tcold < 3500F), to MODE 5 (Told < 2000F), during normal and post accident operations. The time required to cool from 3500F to 2000F is a function of the number of CCW and RHR trains operating. One CCW train is sufficient to remove decay heat during subsequent operations with Tcod < 2000F. This assumes a maximum service water temperature of 100°F occurring simultaneously with the maximum heat loads on the system.

The CCW System satisfies Criterion 3 of 10 CFR 50.36 (Ref. 2).

LCO The CCW trains are independent of each other to the degree that each has separate controls and power supplies and the operation of one does not depend on the other. In the event of a DBA, one CCW train is required to provide the minimum heat removal capability assumed in the safety analysis for the systems to which it supplies cooling water. To ensure this requirement is met, two trains of CCW must be OPERABLE.

At least one CCW train will operate assuming the worst case single active failure occurs coincident with a loss of offsite power.

A CCW train is considered OPERABLE when:

a. Both pumps and associated surge tank are OPERABLE; and

b. The associated piping, valves, heat exchanger, and instrumentation and controls required to perform the safety related function are OPERABLE.

The isolation of CCW from other components or systems not required for safety may render those components or systems inoperable but does not affect the OPERABILITY of the CCW System.

Catawba Units 1 and 2 B 3.7.7-2 Revision No. 0

AC Sources-Operating B 3.8.1 BASES APPLICABILITY (continued)

b. Adequate core cooling Is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.

The AC power requirements for MODES 5 and 6 are covered in LCO 3.8.2, "AC Sources-~-Shutdown."

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.

There is an increased risk associated with entering a MODE or other

- specified condition in the'Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

When entering Required Actions for inoperable offsite circuit(s) and/or DG(s), it is also necessary to enter the applicable Required Actions of any shared systems LCOs when either normal or emergency power to shared components governed by these LCOs becomes inoperable.

These LCOs include 3.7.8, uNuclear Serce Water System (NSWS)";

3.7.10, "Control Room Area Ventilation System (CRAVS)"; 3.7.11, "Control Room Area Chilled Water System (CRACWS)"; and 3.7.12, "Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)-.

A.1 To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining acquired offsitecircut on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not'met. However, if a second

-required circuit fails SR 3.8.1.1,;the second offsite circuit is inoperable, and Condition C,- for two offsite circuits inoperable, is entered.

A.2 - .

Required Action A.2, which only applies If the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function of critical redundant required features.

- These features are powered from the redundant AC electrical power Catawba Units 1 and 2 B 3.8.1-5 ' ' RevisionNo. 2 '

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) train. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.

The Completion Time for Required Action A.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a. The train has no offsite power supplying it loads; and

b. A required feature on the other train is inoperable.

If at any time during the existence of Condition A (one offsite circuit inoperable) a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering no offsite power to one train of the onsite Class 1E Electrical Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with the other train that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associiatczJ with.-shutdown-.-

The remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to Train A and Train B of the onsite Class 1E Distribution System. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period. ..

A.3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Catawba Units 1 and 2 B 3.8.1-6 Revision No. 2

-a, AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

Condition A for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class I E Distribution System.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action A.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified

'condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations inwhich Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action A.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."

- 'This will result in establishing the "time zero" at the time, a: .. GO was initially not met, instead of at the time Condition A was entered.

B.1 . -

To ensure a highly reliable power source remains with an inoperable DG, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1 .1, it is inoperable. Upon offsite circuit inoperability, additional Conditions and Required Actions' must then be entered.

Catawba Units 1 and 2 B 3.8.1-7 Revision No. 2

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

B.2 Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related trains. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis. Redundant required feature failures consist of inoperable features associated with a train, redundant to the train that has an inoperable DG.

The Completion Time for Required Action B.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. A required feature on the other train (Train A or Train B) is inoperable.

If at any time during the existence of this Condition (one DG inoperable) a iC 1.ai,-ed4eaturesubsequently becomes inoperable, this Completion Time would begin to be tracked.

Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DG, results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is Acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

In this Condition, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not Catawba Units 1 and 2 B 3.8.1-8 Revision No. 1

J AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes Into account the OPERABILITY of the redundant counterpart to the Inoperable required feature. Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

B.3.1 and B.3.2

!RequiredAction B.3.1 provides an ailowance to avoid unnecessary testing of OPERABLE DG(s). If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s), the other DG(s) would be declared inoperable upon discovery and Condition E of LCO 3.8.1 would be entered. Once the failure is repaired, the common cause failure no longer exists, and Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s),

performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of that DG.

In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the problem investigation process will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition B.

These Conditions are not required to be entered if the inoperability of the DG is due to an inoperable support system, an independently testable component, or preplanned testing or maintenance. if- required, these I

Required Actions are to be m.,,pleted regardless-of when the inoperable

.DG is restored to OPERABLE status..'-

According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable to

- confirm that the OPERABLE DG(s) is not affected by the same problem as the inoperable DG. -

B.4

,According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class I E Distribution Catawba Units 1 and 2 B 3.8.1-9 Revision N6.1

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

System. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure to meet the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "ND" connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

As in Required Action B.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed time "clock." This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition B was entered.

C.1 and C.2 Required Action C.1, which applies when two offsite circuits are

.inperable, is intended to provide assurance that an event L2'. 4-i coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref. 7) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is appropriate. These features are powered from redundant AC safety trains. This includes motor driven auxiliary feedwater pumps.

Single train features, such as turbine driven auxiliary pumps, are not included in the list.

Catawba Units I and 2 B 3.8.1-10 Revision No. I

AC Sources-Shutdown B. SE B3.8.2 BASES LCO (continued)

The qualified offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the Engineered Safety Feature (ESF) bus(es).

Qualified offsite circuits are those that are described in the UFSAR and are part of the licensing'basis for the unit.

The 4.16 kV essential system is divided Into two completely redundant and independent trains designated A and B, each' consisting of one 4.16 kV switchgear assembly, three 4.16 kV/600 V transformers, two 600 V' load centers, and associated loads.

Normally, each' Class 1E4.16 kV switchgear is 'powered from Its associated non-Class 1E train of the 6.9 kV Normal Auxiliary Power System as discussed In "6.9 kV Normal Auxiliary Power System" in Chapter 8 of the UFSAR. Additionally, an alternate source of power to each 4.16 kV essential switchgear is provided from the 6.9 kV system via two separate and Independent 6.9/4.16 kV transformers. These transformers are shared between units and provide the capability to supply an'altemate source of preferred power to each unit's 4.16 kV

essential switchgear from eitherunit's 6.9 kV system. A key interlock scheme is provided to preclude the possibility of connecting the two units together at'either the 6.9 or 4.16 kV level.,

Each train of the 4.16 kV Essential Auxiliary Power System is also provided with a separate and independent emergency diesel generator to

- supply the Class ' Eloads required -to safelyshut down the unit following a design basis accident. Additionally, each diesel generator is capable of supplying Its associated 4.16 k' blackout switchgear through a connection with the 4.16 kV essential switchgear.

The DG must be capable of starting, accelerating to rated speed and voltage, and connecting to Its respective ESF bus on detection of bus

undervoitage. This sequence must be accomplished within 11 seconds.

The DG must be capable of accepting required loads within the assumed loading sequence Intervals, and continue to'6perate until offsite power can be restored to the ESF buses. These capabilities are required to be met from a variety of initial conditions such as DG In standby with the engine hot and DG in standby at ambient conditions.

Proper sequencing of loads, including tripping of nonessential loads, is a required function for DG OPERABILITY.

Catawba Units 1 and 2 B 3.8.2-3 Revision No'. 0

AC Sources-Shutdown B 3.8.2 BASES LCO (continued)

In addition, proper sequencer operation is an integral part of offsite circuit OPERABILITY since its inoperability impacts on the ability to start and maintain energized loads required OPERABLE by LCO 3.8.10.

It is acceptable for trains to be cross tied during shutdown conditions, allowing a single offsite power circuit to supply all required trains.

APPLICABILITY The AC sources required to be OPERABLE in MODES 5 and 6 and during movement of irradiated fuel assemblies provide assurance that:

a. Systems to provide adequate coolant inventory makeup are available for the irradiated fuel assemblies in the core;

b. Systems needed to mitigate a fuel handling accident are available;

c. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are available; and

d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition.

The AC power requirements for MODES 1, 2, 3, and 4 are covered in LCO 3.8. 1.

ACTIONS When entering Required Actions for inoperable offsite circuit(s) and/or DG(s), it is also necessary to enter the applicable Required Actions of any shared systems LCOs when either normal or emergency power to shared components governed by these LCOs becomes inoperable.

These LCOs include 3.7.8, '"Nuclear Service Water System (NSWS)";

3.7.10, uControl Room Area Ventilation System (CRAVS)"; 3.7.1 1, "Control Room Area Chilled Water System (CRACWS)"; and 3.7.12, "Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)".

Catawba Units 1 and 2 B 3.8.2-4 Revision No.:I

AC Sources-Shutdown B 3.8.2 BASES ACTIONS (continued)

A.1.

An offsite circuit would be considered inoperable if it were not available to one required ESF train. Although two trains are required by LCO 3.8.10, the one train with offsite power available may be capable of supporting sufficient required features to allow continuation of CORE ALTERATIONS and fuel movement. By the allowance of the option to declare required features inoperable, with no offsite power available, appropriate' restrictions will be implemented in accordance with the affected required features LCO's ACTIONS.

A.2.1. A.2.2. A.2.3, A.2.4. B.1. B.2, B.3. and 8.4 With the'offsite circuit not available to all required trains, the option would still exist to declare all required features inoperable. Since this option may involve undesired administrative efforts, the allowance for sufficiently conservative actions is made. With the required DG inoperable, the--.

minimum required diversity of AC power sources is not available. It is,::'

thereforejrequired to suspend CORE ALTERATIONS, movement of irradiated fuel assemblies, and operations involving positive reactivity additions that could result in loss of required SDM (MODE 5) or required boron concentration (MODE 6). Suspending positive reactivity additions that could result in failure to meet the minimum SDM or boron concentration limits is required to assure continued safe operation.

Introduction of coolant inventory must be from sources that have a boron concentration greater than that what would be required in the RCS for minimum SDM or refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation. Introduction of temperature chat;yss including temperature-increases when operating with a positive MTC must also be evaluated to ensure they do not result in a loss of required SDM.. .

Suspension of these activities does not preclude completion of actions to establish 'safe conservative condition. These actions minimize the probability or the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC sources and to continue this action until restoration is accomplished in order to provide the necessary AC power to the unit safety systems.

Catawba Units 1 and 2 B 3.8.2-5 Revision' No. 2

AC Sources-Shutdown B 3.8.2 BASES ACTIONS (continued)

The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required AC electrical power sources should be completed as quickly as possible in order to minimize the time during which the unit safety systems may be without sufficient power.

Pursuant to LCO 3.0.6, the Distribution System's ACTIONS would not be entered even if all AC sources to it are inoperable, resulting in de-energization. Therefore, the Required Actions of Condition A are modified by a Note to indicate that when Condition A is entered with no AC power to any required ESF bus, the ACTIONS for LCO 3.8.10 must be immediately entered. This Note allows Condition A to provide requirements for the loss of the offsite circuit, whether or not a train is de-energized. LCO 3.8.10 would provide the appropriate restrictions for the situation involving a de-energized train.

SURVEILLANCE SR 3.8.2.1 REQUIREMENTS SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are necessary for ensuring the OPERABILITY of the AC sources in other than MODES 1, 2, 3, and 4. SR 3.8.1.8 is not required to be met since only one offsite circuit is required to be OPERABLE. SRs 3.8.1.12 and 3.8.1.19 are not required to be met because the ESF signals, required for the SRs, are not required to be OPERABLE in MODES 5 or 6. SR 3.8.1.17 is not required to be met because the required OPERABLE DG(s) is not required to undergo periods of being synchronized to the offsite circuit.

SR 3.8.1.20 is excepted because starting independence is not required with the DG(s) that is not required to be OPERABLE.

it This-SR is modified by a Note. Thte iesuii forthe Note is to preclude requiring the OPERABLE DG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during performance of SRs, and to preclude deenergizing a required 4160 V ESF bus or disconnecting a required offsite circuit during performance of SRs. With limited AC sources available, a single event could compromise both the required circuit and the DG. It is the intent that these SRs must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit is required to be OPERABLE.

Refer to the corresponding Bases for LCO 3.8.1 for a discussion of each SR.

REFERENCES 1. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

Catawba Units 1 and 2 B 3.8.246 Revision No. I

^' Diesel Fuel Oil, Lube Oil and Starting Air B 3.8.3 t;IllVl:ll I Af4CE REQOUIREMENTS (continued). -

particulates in middle distillate fuels, which includes 2-D diesel fuel. This l method Involves a gravimetric determination of total particulate

concentrationin the fuel oi and has a limit of 10 mg/l. For those designs in which the total stored fuel oil volume is contained In two or more interconnected tanks, each tank must be considered and tested separately. -

The Frequency of this test takes into consideration fuel oil degradation trends that Indicate that particulate concentration Is unlikely to change significantly between Frequency Intervals.

SR 3.8.3.4 This Surveillance ensures that, without the aid of the refill compressor, sufficient air start capacity for each DG is available. The system design requirements provide for a minimum of five engine start cycles without recharging. A start cycle is defined by the DG vendor, but usually Is measured in terms of time (seconds of cranking) or engine cranking speed. The pressure specified in this SR Is intended to reflect the lowest value at which the five starts can be accomplished.

The 31 day Frequency takes into account the capacity, capability, redundancy, and diversity of the AC sources and other indications available'in the control room, including alarms, to alert the operator to below normal air start pressure.

SR 3.8.3.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the fuel storage tanks once every 31 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rairn water, and contaminated fuel oil, and from breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Catawba Units 1 and 2 B 3.8.3-7 -Revision No. 1

Diesel Fuel Oil, Lube Oil and Starting Air B 3.8.3 BASES SURVEILLANCE REQUIREMENTS (continued)

Regulatory Guide 1.137 (Ref. 2). This SR is for preventive maintenance.

The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during performance of the Surveillance.

REFERENCES 1. UFSAR, Section 9.5.4.2.

2. Regulatory Guide 1.137.

3. ANSI N195-1976, Appendix B.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

7. ASTM Standards: D4057; D975; D1298; D4176; D2709; D4294; D6217; D1552; D2622; D1796; and D287.

8. UFSAR, Section 18.2.4.

9. Catawba License Renewal Commitments, CNS-1274.00-00-0016, Section 4.5.

Catawba Units 1 and 2 B 3.8.3-8 Revision No. 2

ML051800634

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