ML022680046

License Amendment, Request for Technical Specifications 3.3.2, Engineered Safety Feature Actuation System Instrumentation, and 3.3.5, Loss of Power Diesel Generator Start Instrumentation

ML022680046
Person / Time
Site:	Catawba
Issue date:	09/12/2002
From:	Gordon Peterson Duke Energy Corp
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
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Download: ML022680046 (23)

Text

SDuke GARY R. PETERSON (rPower Vice President Catawba Nuclear Station A Duke Energy Company Duke Power CN01 VP / 4800 Concord Rd York, SC 29745 803 831 4251 803 831 3221 fax grpeters~duke-energy com September 12, 2002 U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 ATTENTION: Document Control Desk

Subject:

Duke Energy Corporation Catawba Nuclear Station, Units 1 and 2 Docket Numbers 50-413 and 50-414 License Amendment Request for Catawba Nuclear Station Technical Specifications 3.3.2, Engineered Safety Feature Actuation System Instrumentation, and 3.3.5, Loss of Power Diesel Generator Start Instrumentation

Reference:

Letter from Duke Energy Corporation to NRC, same subject, dated December 20, 2001 In the reference letter, Duke Energy Corporation submitted a license amendment request (LAR) for the Catawba Nuclear Station Facility Operating Licenses and Technical Specifications (TS). The purpose of this LAR is to make necessary corrections, make the descriptive portion of these TS easier to apply to plant activities, address overly restrictive requirements, and delete portions of these TS that are not required by regulations.

The NRC provided a request for additional information concerning this LAR via a telephone conference call. The purpose of this letter is to respond to that request. This response addresses items 1, 3, 4, and 5 of the request for additional information. In order to fully respond to item 2, it is necessary for Duke Energy Corporation to conduct additional risk analysis work. Pending the completion of this work, this response will be supplemented. The estimated completion date of the additional risk analysis AooGI www duke-energy corn

U.S. Nuclear Regulatory Commission Page 2 September 12, 2002 work and submittal of the supplementary information is approximately November 1, 2002.

The attachment to this letter contains the NRC request for additional information (items 1, 2, 3, 4, and 5) and Catawba's response to each item.

The original conclusions of the No Significant Hazards Consideration Analysis and the Environmental Assessment as detailed in the reference letter are unchanged as a result of this reply to the request for additional information.

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

Inquiries on this matter should be directed to J. S. Warren at (704) 382-4986 or L. J. Rudy at (803) 831-3084.

G. R. Peterson Attachment

U.S. Nuclear Regulatory Commission Page.3 September 12, 2002 xc w/attachment:

L. A. Reyes, Regional Administrator U. S. Nuclear Regulatory Commission, Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, GA 30303 C. P. Patel (addressee only)

NRC Project Manager (CNS)

U. S. Nuclear Regulatory Commission Mail Stop 0-8 H12 Washington, DC 20555-0001 D. J. Roberts Senior Resident Inspector (CNS)

U. S. Nuclear Regulatory Commission Catawba Nuclear Station - Mail Code CN01RC R. Wingard, Director Division of Radioactive Waste Management South Carolina Bureau of Land and Waste Management 2600 Bull Street Columbia, SC 29201

U.S. Nuclear Regulatory Commission Page 4 September 12, 2002 G. R. Peterson, affirms that he is the person who subscribed his name to the foregoing statement, and that all the matters and facts set forth herein are true and correct to the best of his knowledge.

G6 R. Peterson, Vice President Subscribed and sworn to me: 9/p-I Date Notary Public

" My commission expires:

... I /,q - ;ý- ( -

SEAL

ATTACHMENT NRC REQUEST FOR ADDITIONAL INFORMATION AND CATAWBA RESPONSE (Throughout this attachment, the NRC request for additional information is highlighted in bold type and Catawba's response is shown in normal type.)

On December 20, 200i, Duke Power Company submitted a License Amendment Request (LAR) for Catawba Nuclear Station, Units 1 and 2. In its review of the LAR, the staff has found two apparent licensing issues that must be resolved before the LAR can be granted. These additional points for discussion with the licensee involve proposed Condition T for LCO 3.3.2 Function 6.d, and proposed Condition U for LCO 3.3.2 Function 6.f.

Condition T

1. TS 3.3.2 Condition D addresses one channel of a Function inoperable. For Function 6.d, Condition D requires the inoperable Function 6.d channel to be placed in trip in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, or the unit to be in MODE 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 in 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.

TS 3.3.2 Condition T addresses one Function 6.d channel per bus inoperable. Condition T does not require any actions when only one Function 6.d channel is inoperable because Condition T is applicable only when Function 6.d has become inoperable in two buses.

Consequently, in the proposed TS, one or more Function 6.d channels on the same bus may remain inoperable for an indefinite period, which is significantly less conservative than tripping the Function 6.d channel in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The licensee has not addressed the risk significance of allowing one or more inoperable, untripped Function 6.d channels on the same bus.

Catawba response:

Although Condition T is stated as "One or more channels per bus inoperable.", this in no way is intended to imply that one or more channels would have to become inoperable on both buses before any TS action is required. 'The language proposed in Condition T is consistent with the language presently utilized in TS 3.3.5, which is also expressed on a "per bus" basis. The proposed language is equivalent to interpreting Condition T as "One or more channels inoperable on one or both buses." The "per bus" language is identical to that utilized in.NUREG-1431, "Standard Technical Specifications,'Westinghouse Plants." Catawba has never interpreted the language in TS 3.3.5 as implying that both buses must be affected before the TS requires action to be taken.

2. In the existing TS 3.3.2 Function 6.d, if one channel becomes inoperable on both buses, the Condition D Required Action is applied to both channels; i.e., the two inoperable Function 6.d channels must be placed in Page 1

trip in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, or the unit must be in MODE 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and MODE 4 in 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />.

In the proposed TS 3.3.2 Function 6.d, if one channel per bus becomes inoperable, proposed TS 3.3.2 Condition T requires immediate entry into TS 3.3.5, "Loss of Power (LOP) Diesel Generator Start Instrumentation." In this case, TS 3.3.5 Condition A would require that the two inoperable Function 6.d channels be placed in trip within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. if the Completion Time is not met, TS 3.3.5 Condition C directs the unit operator to enter applicable Condition(s) and Required Action(s) for the associated DG made inoperable by LOP DG start instrumentation (TS 3.8.1, "AC Sources - Operating," or TS 3.8.2, 11AC Sources - Shutdown").

TS 3.8.1 Condition B addresses one DG inoperable.

Condition B requires the following actions and completion times:

A. Performance of SR 3.8.1.1 for the offsite circuits(s) within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and once per 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> thereafter, and B. Declare the required feature(s) supported by the inoperable DG inoperable when its required redundant feature(s) is inoperable within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of discovery of Condition B concurrent with inoperability of redundant required feature(s), and C. Determine OPERABLE DG is not inoperable due to common cause failure within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, or perform SR 3.8.1.2 for the OPERABLE DG within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, and D. Restore DG to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and 6 days from discovery of failure to meet LCO.

Consequently, because TS 3.8.1 does not require the channel(s) to be tripped, proposed TS 3.3.2 Condition T effectively provides a 72-hour allowable outage time (AOT) for restoring TS 3.3.2 Function 6.d channel operability when two buses are affected by TS 3.3.2 Function 6.d inoperability and the operator does not trip the affected channels per TS 3.3.5.

Westinghouse Topical Report WCAP-10271-P-A, "Evaluation of Surveillance Frequencies and Out of Service Times for the Engineered Safety. Features

,Actuation System,"-Supplement 2, Revision 1, dated May 1989, provided licensees the bases for extending the AOT for maintenance of all ESFAS channel components to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for both relay and solid state systems.

Westinghouse Topical Report WCAP-14333-P-A,

"-Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," dated May 1995, and October 1998 (Revision 1), provided licensees the Page 2

bases for extending AOTs beyond the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> AOT provided in WCAP-10271-P-A. As stated in the NRC SER approving WCAP-14333-P-A, for the licensee to extend the AOT-from 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> using WCAP-14333-P A, the licensee must justify the extended test times and AOTs by providing the following plant-specific information:

i. Confirm the applicability of the WCAP-14333-P-A analyses for their plant, and

2. Address the Tier 2 and 3 analyses including the CRMP insights which confirm that these insights are incorporated into their decision making process before taking equipment out of service.

The licensee has not provided this information in its submittal. Consequently, the effective 72-hour AOT granted by reference to TS 3.8.1 through TS 3.3.5 and TS 3.3.2 Function 6.d Condition T is not supported by the licensee's request.

Catawba response:

Catawba disagrees with the NRC position at the beginning of this statement that in the event of one inoperable channel on both buses, that TS 3.3.2 Condition D can be applied to each channel simultaneously. Condition D clearly states "One channel inoperable.", and cannot be interpreted on a "per bus" basis. In the event that one channel is inoperable on both buses, Catawba maintains that there would be no TS 3.3.2 condition governing the existing plant situation; therefore, TS 3.0.3 would apply, necessitating a unit shutdown if the situation could not be corrected within one hour. Application of TS 3.0.3, although required by the existing TS, is inappropriate for this situation, as no actual safety function has been compromised. TS 3.0.3 is usually intended to apply in situations where a safety function has been compromised.

Application of TS 3.0.3 in this situation is also inconsistent with TS 3.3.5, which contains conditions and required actions governing any number of inoperable channels on one or both buses.

Duke Energy Corporation'is presently conducting a'risk analysis in support of the proposed extension of the completion time for inoperable channels as allowed by TS 3.3.2, Condition T, via TS 3.3.5 and TS 3.8.1. Duke Energy Corporation will supplement this response to the NRC request for additional information pending the completion of this risk analysis.

3. In the existing TS 3.3.2 Function 6.d, if more than one Function 6.d channel on one bus becomes inoperable, TS 3.0.3 applies because Condition D Page 3

addresses only one Function 6.d channel inoperable per bus.

In the proposed TS, two Function 6.d channels inoperable on the same bus is not a TS entry condition because Condition T allows one or more channel(s) on the same bus to be inoperable. In this case, the proposed TS 3.3.2 Condition T could be interpreted as a justification for not requiring additional action, since two buses must be affected before the Condition is applicable. Consequently, in the proposed TS, one or more channels per bus may be-declared inoperable without entry into TS 3.0.3.

Catawba response:

Catawba disagrees with the NRC assertion that in the proposed TS 3.3.2, Condition T, two Function 6.d channels inoperable on the same bus is not a TS entry condition.

Condition T does not require that both buses be affected before action is required by the TS. As indicated in the response to Question 1 above, Catawba interprets and has always interpreted the "per bus" language to be applicable when one or both buses are affected. Refer to Catawba's response to Question 1 above.

4. In the existing TS 3.3.2, Function 6.d addresses AFW (heat sink) availability when power to the MFW pumps is lost. In the proposed TS 3.3.2, Function 6.d addresses DG (electrical power) availability when power to the MFW pumps is lost, which does not directly assure at least one SG is capable of providing a heat sink for the RCS. The change in focus for TS 3.3.2 Function 6.d, is not justified by the licensee's submittal.

Catawba response:

When a DG becomes inoperable, TS 3.8.1, Condition B applies. TS 3.8.1 requires that redundant required features (including AFW) be operable when the affected DG is inoperable. The Bases for TS 3.8.1, Required Action B.2 states that this required action 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 critical systems include the AFW System. The Bases states that both the motor driven and turbine driven AFW pumps are considered redundant required features. Therefore, when proposed TS 3.3.2, Condition T requires entry into the applicable condition(s) and required action(s) of TS 3.3.5, which in turn may require the applicable condition(s) and required action(s) of TS 3.8.1 to be entered for the associated inoperable DG, the TS requires the operability Page 4

of redundant required features (including AFW) to be maintained.

On the basis of the above points, the staff cannot approve the addition of Condition T to the TS.

Condition U

5. The licensee proposed adding Condition U to TS 3.3.2 Function 6.f, Auxiliary Feedwater Pump Train A and Train B Suction Transfer on Suction Pressure - Low.

Condition U addresses two or more channels inoperable on a single train, which was not addressed in the existing TS. The proposed Condition U action would require the licensee to declare the associated auxiliary feedwater system train inoperable immediately when the associated instrumentation channels become inoperable. The licensee stated this proposed action would require the operator to enter TS 3.7.5, Auxiliary Feedwater (AFW) System immediately.

When instrumentation in two channels of the AFW pump suction transfer function are inoperable, which would result in the associated AFW train becoming inoperable, the existing TS 3.3.2 Function 6.f requires the unit to be placed in MODE 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> (in accordance with TS 3.0.3). In the proposed TS amendment, the reference to TS 3.7.5 provides a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowable outage time (AOT) when one AFW train is declared inoperable. The licensee claims that the proposed change removes the inconsistency between entering TS 3.0.3 from TS 3.3.2 and having a 72-hour AOT in TS 3.7.5 for the same train being declared inoperable. In the event that multiple channels (i.e., two or more) of this instrumentation become inoperable on both trains, then TS 3.0.3 would still apply.

Westinghouse Topical Report WCAP-10271-P-A, "Evaluation of Surveillance Frequencies and Out of Service Times for the Engineered Safety Features Actuation System,".Supplement 2, Revision 1, dated May 1989, provided licensees the bases for extending the AOT for maintenance of all ESFAS channel components to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for both relay and solid state systems.

Westinghouse Topical Report WCAP-14333-P-A, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," dated May 1995, and October 1998 (Revision 1), provided licensees the bases for extending AOTs beyond the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> AOT Page 5

provided in WCAP-10271-P-A. As stated in the NRC safety evaluation approving WCAP-14333-P-A, for the licensee to extend the AOT from 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> using WCAP-14333-P-A, the licensee must justify the extended test times and AOTs by providing the following plant-specific information:

i. Confirm the applicability of the WCAP-14333-P-A analyses for their plant, and

2. Address the Tier 2 and 3 analyses including the CRMP insights which confirm that these insights are incorporated into their decision making process before taking equipment out of service.

The licensee has not provided this information in its submittal. Consequently, the effective 72-hour AOT permitted by reference to TS 3.7.5 through TS 3.3.2 Function 6.f Condition U is not supported by the licensee's request.

Catawba response:

Duke Energy Corporation has conducted a probabilistic risk assessment (PRA) review of this proposed change. This assessment was based on a similar assessment performed to support a one-time change to the Catawba Unit 1 TS in License Amendment 190, dated April 6, 2001. The values for the change in Core Damage Frequency and Incremental Conditional Core Damage Probability stated below are slightly different from those used in the original analysis to support the temporary change due to extending the data an additional decimal place.

The PRA assessed the impact of the proposed permanent change using measures defined in Regulatory Guide 1.1741 and Regulatory Guide

1. 1772. The risk impacts of the proposed change, to address the inoperability of two or more Auxiliary Feedwater PunLp Suction Transfer channels on a single train, are calculated and compared against the acceptance guidelines in the Regulatory Guides.

The plant-specific assessment was performed to support increased completion times for instrumentation that was not specifically evaluated in Westinghouse Topical Reports WCAP-10271-P-A, Supplement 23 and WCAP-14333-P-A 4 .

Specifically, Duke Energy Corporation evaluated the risk significance of adding Condition U to TS 3.3.2 Function 6.f, Auxiliary Feedwater Pump Train A and Train B Suction Transfer on Suction Pressure - Low. Condition U addresses two or more channels inoperable on a single train. The proposed Condition U requires declaring the associated Auxiliary Feedwater System train inoperable immediately Page 6

when the associated instrumentation channels become inoperable. For the condition of two or more channels inoperable on a single train, existing TS 3.3.2 Function 6.f. requires the unit to be placed in MODE 3 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> (in accordance with TS 3.0.3). The proposed change would reference TS LCO 3.7.5 which provides for a 72-hour Completion Time (CT).

Duke Energy Corporation performed the evaluation using an Internal and External Events PRA with average unavailabilities. The pressure transmitters in question are explicitly modeled in the Catawba PRA. Specifically, a failure of all three of the Train B Auxiliary Feedwater (AFW) to Nuclear Service Water System (NSWS) pressure transmitters was evaluated. A sensitivity study was performed to address any PRA modeling asymmetries between trains. There were insignificant differences in results based on Train A or Train B inoperabilities.

For the proposed change, a delta Core Damage Frequency (ACDF), and an Incremental Conditional Core Damage Probability (ICCDP) were calculated based on the difference between the risk results of current (base) versus the proposed plant configuration utilizing the 72-hour time frame.

The Catawba base case CDF for internal and external events is 4.973E-05/year (no seismic). A qualitative assessment of the significance of the proposed change to the seismic CDF was made. The probability of a seismic event of sufficient magnitude to fail the condensate grade sources of the AFW System is estimated to be less than 2.OE-07 for a 72-hour period. With such a low initiating event probability, the contribution to the risk metrics (i.e.,

change in CDF and ICCDP) is expected to be very small and was therefore neglected as insignificant in the analysis.

The conditional CDF with all three of the pressure transmitters failed on one train is 4.990E-05/year. The results-indicate-an increase in CDF over the base case of 1.7E-07/year which corresponds to an adjusted ACDF of 1.9E 07/reactor year. Regulatory Guide 1.174 indicates that a calculated increase in CDF of less than 1E-06 per reactor year is very small.

The Incremental Conditional Core Damage Probability (ICCDP) for a 72-hour time frame (enter the applicable AFW Page 7

Technical Specification for repair of the instruments) is calculated to be 1.6E-09. Regulatory Guide 1.177 indicates that an ICCDP of less than 5.OE-07 is considered small for a single TS CT change.

The values calculated constitute an acceptable level of risk increase in accordance with Regulatory Guide 1.174 and Regulatory Guide 1.177.

Additional insights can be made as follows:

"* Catawba has committed 5 to the installation of flood protection around the 6900/4160 volt transformers in the turbine building basement which will significantly lower the turbine building flood initiator frequency used in the model.

" The current Catawba PRA model does not reflect the new high temperature reactor coolant pump seals that are installed. A sensitivity analysis 6 has shown that implementation of this change into the PRA is expected to lower the base case CDF by approximately 16%.

Regarding Large Early Release Frequency (LERF), the major contributors to LERF at Catawba are Interfacing Systems LOCAs and seismic events. The ISLOCA is assumed to result in core damage and the AFW System provides no mitigation function for the ISLOCA. The seismic contribution to the LERF is dominated by seismic events of very high ground accelerations that result in certain structural failures.

Seismic events of this magnitude lead to failure of "necessary plant support systems (e.g., AC power) and the unavailability of a single train of AFW to NSWS auto swap is not expected to make a measurable difference to the LERF. Therefore the impact on LERF is very small.

Page 8

ADDITIONAL DISCUSSION REGARDING CATAWBA PRA RESULTS PRA Updates Duke Energy Corporation's Severe Accident Analysis Group (SAAG) periodically evaluates changes to the plant with respect to the assumptions and modeling in the Catawba PRA.

The original Catawba PRA was initiated in July 1984 by Duke Power Company assisted by several outside contractors who performed specialized subtasks. It was a full scope Level 3 PRA with internal and external events. A peer review sponsored by the Electric Power Research Institute (EPRI) was conducted after completion of the draft report. The study was published in an internal Duke Power Company report7 in 1987 as Revision 0 to the PRA.

On November 23, 1988, the NRC issued Generic Letter 88-208, which requested that licensees conduct an Individual Plant Examination (IPE) in order to identify potential severe accident vulnerabilities at their plants. The Catawba response to GL 88-20 was provided by letter dated September 10, 1 9 9 2 9. Catawba's response included an updated Catawba PRA (Revision 1) study.

The Catawba PRA Revision 1 study and the IPE process resulted in a comprehensive, systematic examination of Catawba with regard to potential severe accidents. The Catawba study was again a full-scope, Level 3 PRA with analysis of both the internal and external events. This examination identified the most likely severe accident sequences, both internally and externally induced, with quantitative perspectives on likelihood and fission product release potential. The results of the study prompted changes in equipment, plant configuration and enhancements in plant procedures to reduce vulnerability of the plant to some accident sequences of concern.

By letter dated June 7, 199410, the NRC provided a Safety Evaluation of the internal-events portion of the above Catawba IPE submittal. The conclusion of the NRC letter

[page 16] states:

"The staff finds the licensee's IPE submittal for internal events including internal flooding essentially complete, with the level of detail consistent with the information requested in NUREG-1335. Based on the review of the submittal and the associated supporting information, the Page 9

staff finds reasoha'ble the licensee's IPE conclusion that no fundamental weakness or severe accident vulnerabilities exist at Catawba."

In response to Generic Letter 88-20, Supplement 4, SAAG completed an Individual Plant Examination of External Events'(IPEEE) for severe accidents. This IPEEE was submitted to the NRC by letter dated June 21, 199411. The report contained a summary of the methods, results and conclusions of the Catawba IPEEE program. The IPEEE process and supporting Catawba PRA included a comprehensive, systematic examination of severe accident potential resulting from external initiating events. By letter dated April 12, 199912, the NRC provided an evaluation of the IPEEE submittal. The conclusion of the NRC letter [page 6] states:

"-The staff finds the licensee's IPEEE submittal is complete with regard to the information requested by Supplement 4 to GL 88-20 (and associated guidance in NUREG-1407), and the IPEEE results are reasonable given the Catawba design, operation, and history. Therefore, the staff concludes that the licensee's IPEEE process is capable of identifying the most likely severe accidents and severe accident vulnerabilities, and therefore, that the Catawba IPEEE has met the intent of Supplement 4 to GL 88-20."

In 1996, Catawba initiated Revision 2 of the 1992 IPE and provided the results to the NRC in 199813. In April 2001 Duke Energy Corporation notified the NRC 14 that a voluntary initiative at Catawba to provide backup cooling to the IA and 2A high head safety injection Centrifugal Charging (NV)

Pumps had been completed. In conjunction with the completion of the plant modifications, the Catawba PRA Level 1 analysis was also updated and was designated as Revision 2b. The impact of this modification was to lower the base case CDF.

Currently, -Revision-3 of the-Catawba PRA-is underway. This update, which is a comprehensive revision to the PRA models and associated documentation, is expected to be completed in 2003. The objectives of this update are as follows:

To ensure the models comprising the PRA accurately reflect the current plant, including its physical configurations, operating procedures, maintenance practices, etc.

Page 10

"* To review recent operating experience with respect to updating the frequency of plant transients, failure rates, and maintenance unavailability data.

"* To correct items identified as errors and implement PRA enhancements as needed.

"* To address areas for improvement identified in the recent Catawba PRA Peer Review.

"* To utilize updated Common Cause Analysis data and Human Reliability Analysis data.

PRA maintenance encompasses the identification and evaluation of new information into the PRA and typically involves minor modifications to the plant model. PRA maintenance and updates as well as guidance for developing PRA data and evaluation of plant modifications, are governed by Workplace Procedures. In January 2001, an enhanced manual configuration control process was implemented to more effectively track, evaluate, and implement PRA changes to better ensure the PRA reflects the as-built, as-operated plant. This process was further enhanced in July 2002 with the implementation of an electronic PRA change tracking tool.

Peer Review Process Between March 18-22, 2002, Catawba participated in the Westinghouse Owners Group (WOG) PRA Certification Program.

This review followed a process that was originally developed and used by the Boiling Water Reactor Owners Group (BWROG) and subsequently broadened to be an industry applicable process through the Nuclear Energy Institute (NEI) Risk Applications Task Force. The resulting industry document, NEI-00-02 15,- describes the-overall PRA peer review process. The Certification/Peer Review process is also linked to the ASME PRA Standard1 6 .

NEI has developed draft guidance for self-assessments to address the use of industry peer review results in demonstrating conformance with the ASME PRA standard. This guidance supplements, and is expected to ultimately become part of, NEI-00-02, PRA Peer Review Process Guidance. The Page 11

guidance is intended to support development of NRC draft regulatory guide DG-1122 (Determining Technical Adequacy of PRA Results for Risk-Informed Activities) which will endorse the ASME standard and discuss the industry peer review process as a means of addressing the requirements of the standard.

The objective of the PRA Peer Review process is to provide a method for establishing the technical quality and adequacy of a PRA for a range of potential risk-informed plant applications for which the PRA may be used. The PRA Peer Review process employs a team of PRA and system analysts, who possess significant expertise in PRA development and PRA applications. The team uses checklists to evaluate the scope, comprehensiveness, completeness, and fidelity of the PRA being reviewed. One of the key parts of the review is an assessment of the maintenance and update process to ensure the PRA reflects the as-built plant.

The review team for the Catawba PRA Peer Review consisted of six members. Three-of the members were PRA personnel from other utilities. The remaining three were industry consultants. Reviewer independence was maintained by assuring that none of the six individuals had any involvement in the development of the Catawba PRA or IPE.

A summary of some of the Catawba PRA strengths and recommended areas for improvement from the peer review are as follows:

Strengths

• Aggressive response to past PRA peer reviews

• Knowledgeable personnel

• Culture of continuous improvement

• Documentation of final results and analyses

• Good capture of plant experience into the model

• Rigorous Level 2 and 3 PRA Recommended Areas for Improvement

"* Limited comparison to other plant/utilities PRAs for results and techniques

"* Better documentation of bases for success criteria and HRA timing Page 12

• More focus on realism vs. conservatism in models

• More attention to eliminating old documentation and modeling assiumptions/simplifications

• Consider more efficient methods to streamline recovery/post-processing process The significance levels of the WOG Peer Review Certification process have the following definitions:

A. Extremely important and necessary to address to ensure the technical adequacy of the PRA, the quality of the PRA, or the quality of the PRA update process.

B. Important and necessary to address but may be deferred until the next PRA update.

Based on the draft PRA peer review report, the Catawba PRA received no "A" fact and observation findings but did receive 30 "B" fact and observation findings. The "B" findings have been reviewed and prioritized for incorporation into the PRA. Some of the "B" findings have already been resolved.

Results of Reviews with Respect to this License Amendment Request With respect to proposed Condition U for Function 6.f, the current analysis 17 is the same as was used previously to support a one-time TS change18 for these same instruments.

In a letter dated April 6, 200119, the NRC approved this TS change. The conclusions of the original analysis apply to this permanent TS change request. The numerical values presented in this write-up are slightly different than those presented for the temporary change due to consideration of an additional significant digit in the numerical results.

Consistent with the work place procedures governing PRA analysis, this calculation has undergone independent' checking by a qualified reviewer. Additionally, the Catawba Plant Operations Review Committee (PORC) and Duke Energy Corporation Nuclear Safety Review Board (NSRB) reviewed and approved the original amendment request package.

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PRA Quality Assurance Methods Approved workplace procedures address the quality assurance of the PRA. One way the quality assurance of the Catawba PRA is ensured is by maintaining a set of system notebooks on each of the PRA systems. Each system PRA analyst is responsible for updating a specific system model. This update consists of a comprehensive review of the system including drawings and plant modifications made since the last update as'well as implementation of any PRA change notices that may exist on the system. The analyst's primary focal point is with the system engineer at the site. The system engineer provides information for the update as needed. The analyst will review the PRA model with the system engineer and as necessary, conduct a system walkdown with the system engineer. This interaction is documented in a memorandum.

The system notebooks contain, but are not limited to, documentation on system design, testing and maintenance practices, success criteria, assumptions, descriptions of the reliability data, as well as the results of the quantification. The system notebooks are reviewed and signed off by a second independent person and are approved by the manager of the group.

When any change to the PRA is identified, the same three signature process of identification, review, and approval is utilized to ensure that the change is valid and that it receives the proper priority.

Maintenance Rule Configuration Control 10 CFR 50.65(a) (4), Regulatory Guide 1.18220, and NUMARC 93 012 require that prior to performing maintenance activities, risk assessments shall be performed to assess and manage the increase in risk that may result from proposed maintenance activities. These requirements are applicable for all plant-modes. NUMARC 91-0622 requires utilities to assess and manage the risks that occur during the performance of outages.

Duke Energy Corporation has several Work Process Manual procedures and Nuclear System Directives that are in place at Catawba to ensure the requirements of the Maintenance Rule are implemented. The key documents are as follows:

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"* Nuclear System Directive 415, "Operational Risk Management (Modes 1-3) per 10 CFR 50.65 (a.4),"

Revision 1, April 2002.

"* Nuclear System Directive 403, "Shutdown Risk Management (Modes 4, 5, 6, and No-Mode) per 10 CFR 50.65 (a.4)," Revision 9, February 2002.

"* Work Process Manual, WPM-609, "Innage Risk Assessment Utilizing ORAM-SENTINEL," Revision 5, April 2002.

"* Work .Process Manual, WPM-608, "Outage Risk Assessment Utilizing ORAM-SENTINEL," Revision 5, April 2002.

The documents listed above are used to address the Maintenance Rule requirement and the on-line (and off-line)

Maintenance Policy requirement to control the safety impact of combinations of equipment removed from service. More specifically, the Nuclear System Directives address the process, define the program, and state individual group responsibilities to ensure compliance with the Maintenance Rule.

The Work Process Manual procedures provide a consistent process for utilizing the computerized software assessment tool, ORAM-SENTINEL, which manages the risk associated with equipment inoperability. ORAM-SENTINEL is a Windows-based computer program designed by the Electric Power Research Institute as a tool for plant personnel to use to analyze and manage the risk associated with all risk significant work activities including assessment of combinations of equipment removed from service. It is independent of the requirements of TS and Selected Licensee Commitments.

The ORAM-SENTINEL models for Catawba are based on a "blended" approach of probabilistic (the full Catawba Revision 2b PRA model is utilized) and traditional deterministic approaches. The results of the risk assessment include a prioritized listing of equipment to return to service, a prioritized listing of equipment to remain in service, and potential contingency considerations.

Additionally, prior to the release of work for execution, Operations personnel must consider the effects of severe weather and grid instabilities on plant operation. This qualitative evaluation is inherent of the duties of the Work Control Center Senior Reactor Operator (SRO).

Responses to actual plant risk due to severe weather or Page 15

grid instabilities are programmatically incorporated into applicable plant emergency or response procedures.

References

1. NRC Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Current Licensing Basis," July 1998.

2. NRC Regulatory Guide 1.177, "An Approach for Plant Specific, Risk-Informed Decisionmaking: Technical Specifications," August 1998.

3. Westinghouse Topical Report WCAP-10271-P-A, "Evaluation of Surveillance Frequencies and Out of Service Times for the Engineered Safety Features Actuation System,"

Supplement 2, Revision 1, dated May 1989.

4. Westinghouse Topical Report WCAP-14333-P-A, "Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times," dated May 1995, and October 1998 (Revision 1).

5. Letter Duke Energy Corporation to U.S. Nuclear Regulatory Commission, "Severe Accident Mitigation Alternatives," August 8, 2002.

6. Catawba Nuclear Station, Severe Accident Analysis Group PRA System Documentation - SAAG #725, "Risk Significance Determination for RN Piping Replacement Project," August 29, 2002.

7. "Catawba Nuclear Station Unit 1 Probabilistic Risk Assessment," Volumes 1-3, Duke Power Company, August 18, 1987.

8. Generic Letter 88-20, Individual Plant Examination for Severe Accident Vulnerabilities, USNRC, November 1988.

9. Letter Duke Power Company to Document Control Desk (USNRC), Catawba Units 1 and 2, "Individual Plant Examination (IPE) Submittal in Response to Generic Letter 88-20," September 10, 1992.

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10. Letter USNRC to Duke Power Company, "Safety Evaluation of Catawba Nuclear Station, Units 1 and 2 Individual Plant Examinati6n (IPE) Submittal," Juhe 7, 1994.

11. Letter Duke Power Company to Document Control Desk (USNRC), Catawba Units 1 and 2, "Individual Plant Examination of External Events (IPEEE) Submittal," June 21, 1994.

12. Letter USNRC to Duke Power Company, "CATAWBA NUCLEAR STATION -- REVIEW OF INDIVIDUAL PLANT EXAMINATION OF EXTERNAL EVENTS (IPEEE)," April 12, 1999.

13. Letter Duke Energy Corporation to Document Control Desk (USNRC), Catawba Units 1 and 2, "Probabilistic Risk Assessment (PRA), Revision 2 Summary Report, January 1998."

14. Letter Duke Energy Corporation to Document Control Desk (USNRC), Catawba Units 1 and 2, "Centrifugal Charging Pump Modifications and Catawba PRA Update (Revision 2b)," April 18, 2001.

15. NEI-00-02, "Probabilistic Risk Assessment (PRA) Peer Review Process Guideline," Nuclear Energy Institute, January 2000.

16. "Standard For Probabilistic Risk Assessment for Nuclear Power Plant Applications," ASME RA-S-2002, January 31, 2002.

17. Catawba Nuclear Station, Severe Accident Analysis Group PRA System Documentation - SAAG #636, Revision 1, "Risk Analysis for a One-Time and Permanent Tech Spec Change Regarding One or More Channels of CA to RN Low Suction Transfer Instrumentation Inoperable," September 2002.

18. Letter Duke Energy Corporation to Document Control Desk (USNRC), Catawba Unit 1, -"Proposed Technical Specification (TS), Amendment 3.3.2, Engineered Safety Feature Actuation System (ESFAS) Instrumentation,"

February 20, 2001.

19. Letter USNRC to Duke Energy Corporation, "CATAWBA NUCLEAR STATION, UNIT 1 RE: ISSUANCE OF AMENDMENT,"

April 6, 2001.

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20. NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants,"

May 2000.

21. NUMARC 93-01, Revision 3, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," July 2000.

22. NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management," December 1991.

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