ML052650335

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Exigent License Amendment Request - Emergency Diesel Generator Load Sequencing Relays Improved Technical Specification Surveillance Requirements
ML052650335
Person / Time
Site: Cook  American Electric Power icon.png
Issue date: 09/12/2005
From: Jensen J
Indiana Michigan Power Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
AEP:NRC:5901-06
Download: ML052650335 (20)
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Text

Indiana Michigan Power INDIANA Cook Nuclear Plant MICHIGAN One Cook Place Bridgman.MI 49106 PAoWER' AEP.com A unit of American Electric Powver September 12, 2005 AEP:NRC:5901-06 10 CFR 50.90 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop O-P1-17 Washington, DC 20555-0001

Subject:

Donald C. Cook Nuclear Plant Units 1 and 2 Docket Nos. 50-315 and 50-316 Exigent License Amendment Request - Emergency Diesel Generator Load Sequencing Relays Improved Technical Specifications Surveillance Requirements

References:

1. Letter from M. K. Nazar, Indiana Michigan Power Company, to Nuclear Regulatory Commission Document Control Desk, "Donald C. Cook Nuclear Plant Unit 1 and Unit 2, License Amendment Request - Conversion of Current Technical Specifications (CTS) to Improved Technical Specifications (ITS)," AEP:NRC:4901, dated April 6,2004 (Accession Number ML041200298).
2. Letter from J. Donohew, Nuclear Regulatory Commission, to M. K. Nazar, Indiana Michigan Power Company, "D. C. Cook Nuclear Plant, Units 1 and 2 - Issuance of Amendments for the Conversion to the Improved Technical Specifications with Beyond Scope Issues (TAC Nos. MC2629, MC2630, MC2653 through MC2687, MC2690 through MC2695, MC3152 through MC3157, MC3432 through MC3453),"dated June 1, 2005 (Accession Number ML050620034).

Dear Sir or Madamn In accordance with the provisions of Section 50.90 of Title 10 of the Code of Federal Regulations, Indiana Michigan Power Company (I&M), the licensee for the Donald C. Cook Nuclear Plant (CNP), Units 1 and 2, is submitting a request for an amendment to the Technical Specifications.

This request proposes a revision to replace the more restrictive requirements of Improved Technical Specification (ITS) Surveillance Requirement (SR) 3.8.1.18 with the wording of current Technical Specification (CTS) SR 4.8.1.1.2.e.11, with minor editorial changes. The reason for the proposed revision to the SR for the emergency diesel generator (EDG) load sequencing relays for CNP Units 1 and 2 is discussed in the following paragraphs.

U. S. Nuclear Regulatory Commission AEP:NRC:5901-06 Page 2 In Reference 1, I&M submitted a license amendment request to the Nuclear Regulatory Commission (NRC) for the conversion of the CNP CTS to the ITS consistent with NUREG-1431, "Standard Technical Specifications - Westinghouse Plants," Revision 2. The NRC approved this request in Reference 2. However, the ITS have not yet been implemented.

During preparations for implementing the ITS, I&M discovered an administrative error in Reference 1 involving the conversion of CTS SR 4.8.1.1.2.e.11 to ITS SR 3.8.1.18. Both of these requirements are intended to verify operability of the EDG load sequencing relays. However, the times to be measured and the associated acceptance criterion of ITS SR 3.8.1.18 are not the same as those in CTS SR 4.8.1.1.2.e. 11, even though Reference I indicated that the requirements were the same. ITS SR 3.8.1.18 addresses time intervals between starting of sequenced loads, whereas CTS SR 4.8.1.1.2.e.1 1 addresses acceptable times for the starting of each individual sequenced load.

Reference 1 should have converted the CTS SR 4.8.1.1.2.e. 11 requirements to ITS SR 3.8.1.18 with no change in technical meaning. As a result, both CNP Unit 1 and Unit 2 ITS pages 3.8.1-14 require a change to reflect the current licensing basis, as intended in Reference 1.

This inadvertent change was not recognized by I&M during preparation of Reference 1, and would not have been apparent to the NRC reviewers as a change during preparation of Reference 2. . The CTS pages in Reference 1, as marked to show proposed changes, did not show any revision to the technical requirements of CTS SR 4.8.1.1.2.e.11. Further, there was no annotation to a Discussion of Change that would have indicated to the NRC reviewer that a change was intended. Therefore, the intent to maintain the current licensing basis for this SR was clear in Reference 1. Also, because of the current overall accuracy of the load sequencing relays, an analysis of the predicted performance intervals between each individual load sequencing relay setting indicates that the current installed relays cannot meet the more restrictive ITS 3.8.1.18 requirements. In addition, a review performed by I&M was unsuccessful in identifying a time delay relay capable of meeting the more restrictive ITS 3.8.1.18 requirements. As a result, I&M has determined that the solution to this issue will require a change to the ITS SR 3.8.1.18 requirements. Therefore, I&M requests that NRC approve the request to replace ITS SR 3.8.1.18 with the wording of CTS SR 4.8.1.1.2.e. I1, with minor editorial changes.

The proposed change is being requested on an exigent basis because ITS implementation is scheduled to occur on September 25, 2005, and without this change being approved the implementation date would be required to be extended. In accordance with Reference 2, extending the ITS implementation date beyond October 31, 2005, would require an additional license amendment request seeking NRC approval.

Implementation of the ITS requires significant advance planning and coordination between various departments, and involves verifications performed by each department that all preparations and conditions have been met with consideration for the planned ITS implementation date. These verifications have been either completed or are expected to be completed by the currently planned ITS implementation date. Changing the ITS implementation date would require that these verifications be repeated to ensure they remain acceptable for the new date. In addition,

U. S. Nuclear Regulatory Commission AEP:NRC:5901-06 Page 3 implementation of ITS at CNP will involve changing setpoints for several Reactor Trip System and Engineered Safety Features Actuation System instrumentation channels to support new more restrictive allowable values in the ITS. This has involved significant planning, and the ITS implementation date was selected primarily to accommodate these setpoint changes in accordance with, and with the least amount of disruption of, the normal work planning cycle. The specific week for ITS implementation within the 13-week work planning cycle was selected because there are no other planned activities that would interfere with or increase risk of plant transients occurring during the maintenance activities required to perform these setpoint changes. Since the normal work planning cycle involves a 13-week schedule, missing the currently planned ITS implementation date would require either a delay in final implementation of at least 13 weeks, or a significant effort to revise the current plans and schedules.

Therefore, it would be an undue burden on I&M to delay implementation of the other changes approved by the NRC as part of ITS to accommodate this single requirement, given that the proposed requirement consistent with the current licensing basis would ensure safe operation of the facility. Thus, I&M requests NRC review and approval by September 23, 2005, to support ITS implementation on September 25,2005. I&M requests an implementation period following approval consistent with implementation of the ITS.

The enclosure to this letter provides an affirmation pertaining to the statements made in this correspondence. Attachment 1 provides a description of the proposed change and confirmation of applicability. In accordance with 10 CFR 50.91(a)(6)(vi), an explanation of the exigency and why it cannot be avoided is also provided in Attachment 1. Attachment 2 provides the Unit 1 and Unit 2 ITS pages marked to show the proposed changes. Attachment 3 provides the proposed Unit 1 and Unit 2 ITS pages. No changes to the CTS pages are proposed.

This letter contains no new commitments. Should you have any questions, please contact Mr. John A. Zwolinski, Safety Assurance Director at (269) 466-2428.

Sincerely, Jensen Site Vice President GEW/rdw

U. S. Nuclear Regulatory Commission AEP:NRC:5901-06 Page 4

Enclosure:

Affirmation Attachments:

1. Description and Assessment
2. CNP Unit 1 and Unit 2 Technical Specification Pages Marked to Show Proposed Changes
3. CNP Unit I and Unit 2 Technical Specification Pages with the Proposed Changes Incorporated c: T. H. Boyce, NRC Washington, DC J. L. Caldwell, NRC Region III K. D. Curry, Ft. Wayne AEP, w/o enclosure/attachments J. N. Donohew, NRC Washington, DC P. C. Hearn, NRC Washington, DC J. T. King, MPSC, w/o enclosure/attachments MDEQ - WHMD/RPMWS, w/o enclosure/attachments NRC Resident Inspector D. W. Spaulding - NRC Washington, DC

Enclosure to AEP:NRC:5901-06 AFFIRMATION I, Joseph N. Jensen, being duly sworn, state that I am.Site Vice President of Indiana Michigan Power Company (I&M), that I am authorized to sign and file this request with the Nuclear Regulatory Commission on behalf of I&M, and that the statements made and the matters set forth herein pertaining to I&M are true and correct to the best of my knowledge, information, and belief.

Indiana Michigan Power Company Site Vice President SWORN TO AND SUBSCRIBED BEFORE ME THIS 12Y' DAY OF .kthR1 2005

\` ot* Public My Commission Expires a1 Ikio-q:

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.4 Attachment 1 to AEP:NRC:5901-06 Description and Assessment

1.0 INTRODUCTION

This request proposes an amendment to the Technical Specifications for the Donald C. Cook Nuclear Plant (CNP), Units 1 and 2, to replace the more restrictive requirements of Improved Technical Specification (ITS) Surveillance Requirement (SR) 3.8.1.18 with the wording of current Technical Specification (CTS) SR4.8.1.1.2.e.11, with minor editorial changes. The reason for the proposed revision to the SR for the emergency diesel generator (EDG) load sequencing relays for CNP Units 1 and 2 is discussed in the following paragraphs.

In Reference 1, Indiana Michigan Power Company (I&M) submitted a license amendment request to the Nuclear Regulatory Commission (NRC) for the conversion of the CNP CTS to the ITS consistent with NUREG-1431, "Standard Technical Specifications - Westinghouse Plants,"

Revision 2. The NRC approved this request in Reference 2. However, the ITS have not yet been implemented.

During preparations for implementing the ITS, I&M discovered an administrative error .in Reference 1 involving the conversion of CTS SR 4.8.1.1.2.e.1I to ITS SR 3.8.1.18. Both of these requirements are intended to verify operability of the EDG load sequencing relays.

However, the times to be measured and the associated acceptance criterion of ITS SR 3.8.1.18 are not the same as those in CTS SR 4.8.1.1.2.e.11, even though Reference 1 indicated that the requirements were the same. ITS SR 3.8.1.18 addresses time intervals between starting of sequenced loads, whereas CTS SR 4.8.1.1.2.e.11 addresses acceptable times for the starting of each individual sequenced load. Reference 1 should have converted the CTS SR 4.8.1.1.2.e. 11 requirements to ITS SR 3.8.1.18 with no change in technical meaning. As a result, both CNP Unit 1 and Unit 2 ITS pages 3.8.1-14 require a change to reflect the current licensing basis, as intended in Reference 1.

This inadvertent change was not recognized by I&M during preparation of Reference 1, and would not have been apparent to the NRC reviewers as a change during preparation of Reference 2. The CTS pages in Reference 1, as marked to show proposed changes, did not show any revision to the technical requirements of CTS SR 4.8.1.1.2.e. 11. Further, there was no annotation to a Discussion of Change that would have indicated to the NRC reviewer that a change was intended. Therefore, the intent to maintain the current licensing basis for this SR was clear in Reference 1. Also, because of the current overall accuracy of the load sequencing relays, an analysis of the predicted performance intervals between each individual load sequencing relay setting indicates that the current installed relays cannot meet the more restrictive ITS 3.8.1.18 requirements. In addition, a review performed by I&M was unsuccessful in identifying a time delay relay capable of meeting the more restrictive ITS 3.8.1.18 requirements. As a result, I&M has determined that the solution to this issue will require a change to the ITS SR 3.8.1.18 requirements. Therefore, I&M requests that NRC approve the to AEP:NRC:5901-06 Page 2 request to replace ITS SR 3.8.1.18 with the wording of CTS SR4.8.1.1.2.e.11, with minor editorial changes.

The proposed change is being requested on an exigent basis because ITS implementation is scheduled to occur on September 25, 2005, and without this change being approved the implementation date would be required to be extended. This would present an undue burden on I&M, and would delay implementation of the many benefits of the ITS as recognized by the NRC in Reference 2. Therefore, in accordance with 10 CFR 50.91(a)(6)(vi), an explanation of the exigency and why it cannot be avoided is provided in Section 9.0 of this attachment.

2.0 DESCRITON OF PROPOSED AMENDMENT I&M proposes ITS SR 3.8.1.18 be revised for both CNP Units I and 2 to state the following:

"Verify that the automatic sequence timing relays are OPERABLE with each load sequence time within +/- 5% of its required value and that each load is sequenced on within the design allowable time limit."

3.0 BACKGROUND

The emergency power source for each CNP unit consists of two 4160 volt, 3-phase, 60 cycle, 3500 kilowatt EDGs. The EDGs are sized at 3500 kilowatts each to assure available power to operate the required engineered safeguard equipment assuming a loss-of-offsite power concurrent with a loss-of-coolant accident with or without containment spray. The emergency power sources for the two CNP units are similar and are electrically and physically isolated from one another, as are the EDG sets for each unit. Each EDG is full capacity with one supplying power to 4160 volt buses TIlA and TIlB (Unit 1) or T21A and T21B (Unit 2), and the other supplying power to TI iC and Ti ID (Unit 1) or T21C and T21D (Unit 2).

Loss of voltage to the 4160 volt buses above is sensed by loss of voltage relays. Upon sensing a loss of voltage, master relays automatically start the EDGs, trip the normal feed circuit breakers for the 4160 volt buses and trip all motor feeder breakers and 480 volt bus transformer feeder breakers on the buses, the 600 volt bus tie breaker, all non-essential 600 volt feeder breakers and 480 volt bus breakers. The EDG circuit breaker which connects the EDG output to the 4160/600 volt bus system is automatically closed when the EDG reaches 95% of full speed. The EDGs supply power to 600 volt buses (I IA, li B, I iC, and li D for Unit 1, and 21A, 21B, 21C, and 21D for Unit 2) through the 4160 volt buses (Ti lA, T1i1B, TI iC, and Ti ID for Unit 1, and T21A, T21B, T21C, and T21D for Unit 2) and transformers (TRIlA, TR11B, TR11C, and TR1lD for Unit 1, and TR21A, TR21B, TR21C, and TR21D for Unit 2), respectively. The 600 volt bus crosstie breakers are racked out in Modes 1 through 4, and otherwise cannot close automatically after the EDG start and closure of associated EDG output breakers, thus eliminating the possibility of parallel operation of EDGs.

to AEP:NRC:590i'06 Page 3 Each EDG comes up to speed and is capable of accepting load within 10 seconds. If either EDG fails to start, the remaining one is capable of supplying the required engineered safeguard load.

A safety injection signal will also start the EDGs. To avoid overloading of the EDG, the non-essential loads are shed when a safety injection occurs and the safety busses are energized from the EDGs.

Under accident conditions, the required engineered safeguard equipment loads are sequentially connected to the bus by the individual load sequencing relays. The sequencing logic controls the timing of permissive and starting signals to motor breakers to prevent overloading of the EDGs due to high motor starting currents by ensuring that sufficient time exists for the EDG to restore frequency and voltage prior to applying the next load, and that safety analysis assumptions regarding required engineered safeguard equipment time delays are not violated.

The individual EDG load sequencing relay for each load is independent of the relays for the other loads. When the EDG reaches 95% of full speed, the EDG 95% relay actuates signaling the EDG output breaker to close, and each individual EDG load sequencing relay begins timing the start of its respective load.

CTS SR 4.8.1.1.2.e.1 1 requires the following surveillance to be performed:

"Verifying that the automatic sequence timing relays are OPERABLE with each load sequence time within plus or minus 5% of its required value and that each load is sequenced on within the design allowable time limit."

The method used to perform this surveillance is to time the response of each individual component (i.e., engineered safeguards pump) motor starting circuit from the time the EDG 95%

relay actuates until the component breaker has closed. The timed response includes the individual time delay for each of the load sequencing relays.

The required value for each individual component circuit time delay is based on calculations performed that ensure that, for the worst-case allowable time delay between any two component breakers closing assuming the 5% tolerance allowed, there is sufficient time for the EDG to recover adequate voltage and frequency following starting of one component to support the successful start of the next associated component and continued operation of all components already sequenced onto the buses. The design allowable time limit for each sequenced load is based on ensuring that each component starts and operates in accordance with the assumptions of the accident analyses.

Because of the intent of CTS SR 4.8.1.1.2.e.I 1 and the surveillance method used, time delays between sequenced loads are not measured or calculated. This is because the calculations supporting the required value, including assumption of the 5% tolerance on each individual load

Attachment I to AEP:NRC:5901-06 Page 4 sequencing relay time, provide acceptance criterion that, if met, ensure that the time delay between sequenced loads is acceptable.

ITS SR 3.8.1.18 requires the following surveillance to be performed:

"Verify interval between each sequenced load block is within + 5% of design interval for each emergency time delay relay."

Therefore, the CTS SR 4.8.1.1.2.e.1 1 acceptance criterion is based upon + 5% of each individual load sequencing relay setting, while the ITS 3.8.1.18 acceptance criterion is based upon +/- 5% of the interval between each individual load sequencing relay setting, which is a more restrictive requirement. This is further demonstrated in the table below:

Nominal Setting Interval +/-5% Setting +/-5%Interval Component (Sec) (Sec() (Sec)

Centrifugal Charging Pump 3 3 0.15 0.15 Safety Injection Pump 7 4 0.35 0.2 Residual Heat Removal Pump 11 4 0.55 0.2 Component Cooling Water Pump 15 4 0.75 0.2 Essential Service Water Pump 20 5 1.0 0.25 Motor Driven Auxiliary Feedwater Pump 25 5 1.25 0.25 Containment Spray Pump 31* 6 1.55 0.3 Non-Essential Service Water Pump 37* 12 1.85 0.6

Because of the current overall accuracy of the load sequencing relays, an analysis of the predicted performance intervals between each individual load sequencing relay setting indicates that the current installed relays cannot meet the more restrictive ITS 3.8.1.18 requirements. In addition, a review performed by I&M was unsuccessful in identifying a time delay relay capable of meeting the more restrictive ITS 3.8.1.18 requirements. Therefore, I&M has determined that the solution to this issue will require a change to replace ITS SR 3.8.1.18 with the wording of CTS SR 4.8.1.1.2.e. 11, with minor editorial changes, consistent with the current licensing basis.

4.0 REGULATORY REQUIREMENTS AND GUIDANCE In addition to the multiple ties to outside sources for emergency power, the EDG units are provided as backup power supplies for the case of loss of all offsite power. The EDGs are capable of operating sufficient core cooling and containment cooling equipment to ensure an acceptable post-accident pressure transient in the affected unit, and safe shutdown of the other to AEP:NRC:5901-06 Page 5 unit, even if one EDG fails to operate in each unit. The design of the CNP emergency power system is in accordance with Plant Specific Design Criterion (PSDC) 39, "Emergency Power,"

as described in the CNP Updated Final Safety Analysis Report (UFSAR), Section 1.4.7.

PSDC 39 states the following:

"An emergency power source shall be provided and designed with adequate independency, redundancy, capacity, and testability to permit the functioning of the engineered safety features and protection systems required to avoid undue risk to the health and safety of the public. This power source shall provide this capacity assuming a failure of a single active component."

In addition, PSDC 41, "Engineered Safety Features Performance Capability," in CNP UFSAR Section 1.4.7, states the following:

"Engineered Safety Features, such as the Emergency Core Cooling System and the Containment Spray System, shall provide sufficient performance capability to accommodate the failure of any single active component without resulting in undue risk to the health and safety of the public."

Therefore, in support of these two criteria, the EDGs must be capable of starting and accepting the sequenced loads without becoming overloaded, and providing the emergency power necessary to support the performance capability of the Engineered Safety Features assumed in the accident analyses. In order to assure these criteria are met, the EDGs must be designed with features that provide an adequate interval between starting of each sequenced load to allow EDG frequency and voltage to recover before the next sequenced load is connected. Allowing the EDG frequency and voltage to recover ensures that the EDG capacity to start each new load is not compromised, and already operating loads do not stall resulting in overloading and possible failure of the EDG.

5.0 TECHNICAL ANALYSIS

Both the CTSSR4.8.1.1.2.e.11 and ITSSR3.8.1.18 requirements ensure that the load sequencing relays are OPERABLE and capable of performing their design functions. The required value for each individual component circuit time delay is based on calculations performed that ensure that, for the worst-case allowable time delay between any two component breakers closing assuming the 5% tolerance allowed, there is sufficient time for the EDG to recover adequate voltage and frequency following starting of one component to support the successful start of the next associated component and continued operation of all components already sequenced onto the buses. The design allowable time limit for each sequenced load is based on ensuring that each component starts and operates in accordance with the assumptions of the accident analyses.

to AEP:NRC:5901-06 Page 6 In addition to adequately determining the capability of the load sequencing relays to perform their design functions, replacing the requirements of ITS SR 3.8.1.18 with the same technical requirements as CTS SR 4.8.1.1.2.e. 11 does not create a conflict with other ITS technical requirements.

Because the requirements of CTS SR 4.8.1.1.2.e.1 1 are acceptable for ensuring that the load sequencing relays are capable of performing their design functions, and do not create a conflict with other ITS technical requirements, revising ITS SR 3.8.1.18 to apply the methodology and acceptance criterion of CTS SR 4.8.1.1.2.e.1 1 is acceptable from a technical perspective.

6.0 REGULATORY ANALYSIS

10 CFR 50.36(c)(3), "Surveillance Requirements" stipulates that surveillances be performed to assure the necessary quality of systems and components be maintained, the facility operations will be within safety limits, and that the limiting condition for operations will be met. Both the CTS SR4.8.1.1.2.e.11 and ITS SR 3.8.1.18 requirements ensure that the EDG load sequencing relays are OPERABLE by ensuring that the relays are capable of performing their required safety functions. In both cases, the EDGs are provided with acceptable protection from overloading during starting of the sequenced loads, and the sequenced loads are started within the times assumed in the accident analyses and are provided with sufficient power to ensure performance capability is also within the assumptions of the accident analyses. In addition, replacing the requirements of ITS SR 3.8.1.18 with the requirements of CTS SR 4.8.1.1.2.e.11 does not create a conflict with other ITS regulatory requirements. Because the requirements of CTS SR 4.8.1.1.2.e.11 are acceptable for establishing operability of the load sequencing relays in compliance with 10 CFR 50.36(c)(3) and do not create a conflict with other ITS regulatory requirements, revising the requirements of ITS SR 3.8.1.18 to apply the methodology and acceptance criterion of CTS SR 4.8.1.1.2.e.11 is acceptable.

7.0 NO SIGNIFICANT HAZARDS CONSIDERATION Indiana Michigan Power Company (I&M) has evaluated whether or not a significant hazards consideration is involved with the proposed change by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of Amendment," as discussed below:

1. Does the proposed change involve a significant increase in the probability of occurrence or consequences of an accident previously evaluated?

Response: No Probability of Occurrence of an Accident Previously Evaluated The proposed change replaces an Improved Technical Specification (ITS) Surveillance Requirement (SR) for the emergency diesel generator (EDG) load sequencing relays with the

Attachment I to AEP:NRC:590i-06 Page 7 requirements of a current Technical Specifications (CTS) SR, consistent with the current licensing basis. The function of the EDG load sequencing relays is only mitigative and is not needed unless an accident and a loss of offsite power occurs. The EDG load sequencing relays do not affect any accident initiators or precursors. Replacing the ITS SR methodology and acceptance criterion with that of the existing CTS SR does not affect the EDG load sequencing relays interaction with any system whose failure or malfunction can initiate an accident. Therefore, the probability of occurrence of an accident previously evaluated is not significantly increased.

Consequences of an Accident Previously Evaluated The function of the EDG load sequencing relays is to ensure proper operation of the EDGs and Engineered Safety Features to mitigate accidents that result in a safety injection actuation signal, with or without a containment spray actuation signal, concurrent with a loss of offsite power. The function of the EDG load sequencing relays is not affected by this change, and the EDGs and Engineered Safety Features will remain- capable of mitigating the consequences of design basis accidents in accordance with the approved accident analyses.

Therefore, the consequences of an accident previously evaluated are not significantly increased.

2. Does the proposed change create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No The proposed change replaces an ITS SR for the EDG load sequencing relays with the requirements of a CTS SR, consistent with the current licensing basis. There are no new failure modes for the EDG load sequencing relays created and the EDG load sequencing relays are not an initiator of any new or different kind of accident. The proposed change does not affect the interaction of the EDG load sequencing relays with any system whose failure or malfunction can initiate an accident. Therefore, the proposed change does not create the possibility of a new or different kind of accident from any previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No The margins of safety applicable to the proposed change are those associated with the availability of the EDG load sequencing relays to perform their safety function in support of the EDGs and the Engineered Safety Features mitigating safety functions. The proposed change to replace the more restrictive ITS SR methodology and acceptance criterion with that of the CTS SR is in compliance with the current licensing basis and does not impact the margins of safety applicable to any other ITS requirement, and there will be no reduction in

2st0'z ~s:' to AEP:NRC:5901-06 Page 8 the safety margins associated with the capability of the EDG load sequencing relays to perform their safety function. Therefore, the proposed change does not involve a significant reduction in margin of safety.

In summary, based upon the above evaluation, I&M has concluded that the proposed change involves no significant hazards consideration under the standards set forth in 10 CFR 50.92(c),

and, accordingly, a finding of "no significant hazards consideration" is justified.

8.0 ENVIRONMENTAL EVALUATION I&M has evaluated this license amendment request against the criteria for identification of licensing and regulatory actions requiring environmental assessment in accordance with 10 CFR 51.21. I&M has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or SR. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to .10 CFR 51.22(b), 'no environmental impact statement or environmental assessment needs to be prepared concerning the proposed amendment.

9.0 EXPLANATION OF EXIGENCY The proposed change is being requested on an exigent basis because ITS implementation is scheduled to occur on September 25, 2005, and without this change being approved the implementation date would be required to be extended. In accordance with Reference 2, extending the ITS implementation date beyond October 31, 2005, would require an additional license amendment request seeking NRC approval.

Implementation of the ITS requires significant advance planning and coordination between various departments, and involves verifications performed by each department that all preparations 'and* conditions have been met with consideration for the planned ITS implementation date. These verifications have been either'completed or are expected to be completed by the currently planned ITS implementation date. Changing the ITS implementation date would require that these verifications be repeated to ensure they remain acceptable for the new date. In addition, implementation of ITS at CNP will involve changing setpoints for several Reactor Trip System and Engineered Safety Features Actuation System instrumentation channels to support new more restrictive allowable values in the ITS; This has involved significant planning, and the ITS implementation date was selected primarily to accommodate these setpoint changes in accordance with, and with the least amount of disruption of, the normal work planning cycle. The specific week for ITS implementation within the 13-week work planning to AEP:NRC:5901-06 Page 9 cycle was selected because there are no other planned activities that would interfere with or increase risk of plant transients occurring during the maintenance activities required to perform these setpoint changes. Since the normal work planning cycle involves a 13-week schedule, missing the currently planned ITS implementation date would require either a delay in final implementation of at least 13 weeks, or a significant effort to revise the current plans and schedules.

Therefore, it would be an undue burden on I&M to delay implementation of the other changes approved by the NRC as part of ITS to accommodate this single requirement, given that the proposed requirement consistent with the current licensing basis would ensure safe operation of the facility.

I&M could not have avoided the exigency due to the short duration between when the problem was discovered involving the inadvertent more restrictive change in the conversion of CTS SR 4.8.1.1.2.e.11 to ITS SR 3.8.1.18, and the date when ITS implementation is planned. In addition, as discussed earlier with the NRC staff, I&M took prompt actions upon discovering this issue, and had submitted a request that this revision to the ITS be approved as an administrative change as described in Reference 3. However, subsequent to that submittal, the NRC staff determined that the request should involve a license amendment request in accordance with 10 CFR 50.90. Therefore, additional time between the date when this problem was discovered and submittal of this request has elapsed, resulting in a shorter duration for resolving this issue without changing the planned ITS implementation date. Thus, this submittal supersedes Reference 3 in its entirety, and is requested to be approved on an exigent basis as described above to support ITS implementation on September 25, 2005.

10. REFERENCES
1. Letter from M. K Nazar, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant Unit 1 and Unit 2, License Amendment Request - Conversion of Current Technical Specifications (CTS) to Improved Technical Specifications (ITS),"

AEP:NRC:4901, dated April 6, 2004 (Accession Number ML041200298).

2. Letter from J. Donohew, NRC, to M. K Nazar, I&M, "D. C. Cook Nuclear Plant, Units 1 and 2 - Issuance of Amendments for the Conversion to the Improved Technical Specifications with Beyond Scope Issues (TAC Nos. MC2629, MC2630, MC2653 through MC2687, MC2690 through MC2695, MC3152 through MC3157, MC3432 through MC3453)," dated June 1, 2005 (Accession Number ML050620034).
3. Letter from D. P. Fadel, I&M, to NRC Document Control Desk, "Donald C. Cook Nuclear Plant Unit 1 and Unit 2, Correction of Administrative Error for Improved Technical Specifications (TAC Nos. MC2629, MC2630, MC2653 through MC2687, MC2690 through MC2695, MC3152 through MC3157, MC3432 through MC3453),"

AEP:NRC:5901-05, dated August 5,2005 (Accession Number ML052280307).

Attachment 2 to AEP:NRC:5901-06 CNP UNIT 1 AND UNIT 2 TECHNICAL SPECIFICATION PAGES MARKED TO SHOW CHANGES Paaes Affected Unit 1: 3.8.1-14 Unit 2: 3.8.1-14

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AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.18 ------------------------------NOTE-------------------------------

This Surveillance shall not normally be performed in MODE 1,2, 3, or4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify interval between each eguenco ad block 24 months Olt S _ within

+/-5% of design interval for each emergcncy time delay c Cook Nuclear Plant Unit 1 3.8.1 -14 Amendment No. l9

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I I AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.18 ------------------------------NOTE-------------------------------

This Surveillance shall not normally be performed in MODE 1, 2, 3, or4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify interval betweeR each s -Ged load block 24 months wa .ii' ~

§.:Ip e:Z....s..~siEo W NE@,s,f>.s. ,ij;....... .. .

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., timl within 5% of e design achmoae time

01. axtgtii Cook Nuclear Plant Unit 2 3.8.1 -14 Amendment No. 269 1

Attachment 3 to AEP:NRC:5901-06 CNP UNIT 1 AND UNIT 2 TECHNICAL SPECIFICATION PAGES WITH THE PROPOSED CHANGES INCORPORATED Pages Affected Unit 1: 3.8.1-14 Unit 2: 3.8.1-14

-; . -a AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.18 -------------------------------NOTE----------------------------

This Surveillance shall not normally be performed in MODE 1, 2, 3, or4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify that the automatic sequence timing relays are 24 months OPERABLE with each load sequence time within

+/- 5% of its required value and that each load is sequenced on within the design allowable time limit.

Cook Nuclear Plant Unit 1 3.8.1 -14 Amendment No. l8

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AC Sources - Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.18 ------------------------------ NOTE-------------------------------

This Surveillance shall not normally be performed in MODE 1, 2, 3, or 4. However, this Surveillance may be performed to reestablish OPERABILITY provided an assessment determines the safety of the unit is maintained or enhanced. Credit may be taken for unplanned events that satisfy this SR.

Verify that the automatic sequence timing relays are 24 months OPERABLE with each load sequence time within AO%of its required value and that each load is sequenced on within the design allowable time limit.

Cook Nuclear Plant Unit 2 3.8.1-14 Amendment No.26 I 1..

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