L-PI-09-017, License Amendment Request (LAR) to Apply Surveillance Requirement (SR) 3.0.2 Interval Extension to SR 3.8.1.8

License Amendment Request (LAR) to Apply Surveillance Requirement (SR) 3.0.2 Interval Extension to SR 3.8.1.8

ML090641102
Person / Time
Site:	Prairie Island
Issue date:	03/05/2009
From:	Wadley M Northern States Power Co, Xcel Energy
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-PI-09-017
Download: ML090641102 (29)

Text

Xcel Energym L-PI-09-017 10 CFR 50.90 U S Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306 License Nos. DPR-42 and DPR-60 License Amendment Request (LAR) to Applv Surveillance Requirement (SR) 3.0.2 Interval Extension to SR 3.8.1.8 Pursuant to 10 CFR 50.90, the Northern States Power Company, a Minnesota corporation (NSPM), doing business as Xcel Energy, hereby requests an amendment to the Technical Specifications (TS) for the Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2, to revise TS 3.8.1, "AC Sources - Operating," SR 3.8.1.8 Frequency to allow use of the SR 3.0.2 interval extension (1.25 times the specified 24 month Frequency). This would be an exception to the SR 3.0.2 limitations in the PINGP TS which do not allow use of the interval extension for SRs with a 24 month Frequency.

NSPM has evaluated the proposed changes in accordance with 10 CFR 50.92 and concluded that they involve no significant hazards consideration.

The enclosure to this letter contains the licensee's evaluation of the proposed changes.

NSPM requests approval of this LAR within one calendar year of the submittal date.

Upon NRC approval, NSPM requests 90 days to implement the associated changes. In accordance with 10 CFR 50.91, NSPM is notifying the State of Minnesota of this LAR by transmitting a copy of this letter and enclosure to the designated State Official.

If there are any questions or if additional information is needed, please contact Mr. Dale Vincent, P.E., at 651-388-1121.

Summary of Commitments This letter contains no new commitments and no revisions to existing commitments 1717 Wakonade Drive East Welch, Minnesota 55089-9642 Telephone: 651.388.1 121

Document Control Desk Page 2 I declare under penalty of perjury that the foregoing is true and correct.

Executed on Michael D. Wadley u Site Vice President, Prairie Island Nuclear Generating Plant Units 1 and 2 Northern States Power Company - Minnesota

Enclosure:

Evaluation of Proposed Changes cc: Administrator, Region Ill, USNRC Project Manager, Prairie Island, USNRC Resident Inspector, Prairie Island, USNRC State of Minnesota

ENCLOSURE Evaluation of the Proposed Changes License Amendment Request (LAR) to Apply Surveillance Requirement (SR) 3.0.2 Interval Extension to SR 3.8.1.8

1.

SUMMARY

DESCRIPTION

2. DETAILED DESCRIPTION 2.1 Proposed Changes

2.2 Background

3. TECHNICAL EVALUATION

4. REGULATORY SAFETY ANALYSIS 4.1 Applicable Regulatory Requirementslcriteria 4.2 Precedent 4.3 Significant Hazards Consideration 4.4 Conclusions

5. ENVIRONMENTAL CONSIDERATION

6. REFERENCES ATTACHMENTS:

1. Technical Specification Pages (Markup)

2. Bases Pages (Markup) (For information only)

3. Technical Specification Pages (Retyped)

4. Application of NEI 04-10 Guidance Document to SR 3.8.1.8 interval extension Page 1 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension

1.

SUMMARY

DESCRIPTION This LAR is a request to amend Operating Licenses DPR-42 and DPR-60 for Prairie Island Nuclear Generating Plant (PINGP) Units 1 and 2.

Northern States Power Company, a Minnesota corporation (NSPM) requests Nuclear Regulatory Commission (NRC) review and approval of proposed revisions to Technical Specification (TS) 3.8.1, "AC Sources-Operating", Surveillance Requirement (SR) 3.8.1.8 which will allow application of the SR 3.0.2 interval extension (1.25 times the specified 24 month Frequency) for performance of this surveillance. This would be an exception to the limitations specified in the PINGP TS SR 3.0.2 for SRs with a 24 month Frequency.

2. DETAILED DESCRIPTION 2.1 Proposed Changes Brief descriptions of the associated proposed TS changes are provided below along with discussions of the justification for each change. The specific wording changes to the TS are provided in Attachments 1 and 3 to this enclosure.

TS 3.8.1, "AC Sources-Operating": This LAR proposes to revise SR 3.8.1.8 by the addition of a new Frequency Note which allows application of the SR 3.0.2 interval extension (1.25 times the specified interval), thus 30 months is the longest allowed interval between performances of this SR. This would be an exception to the restrictions on use of the SR 3.0.2 interval extension with 24 month SR Frequencies in the PINGP TS. This change is acceptable because this surveillance is usually passed when performed and this test interval is adequate to demonstrate that the emergency diesel generators (EDGs) function as designed. This test interval is also consistent with other plants in the industry that specify its performance on a 24-month Frequency.

Although Bases changes are not a part of this LAR, Attachment 2 to this enclosure includes marked up Bases pages for information. The changes proposed in are directly related to the changes proposed to TS 3.8.1.

In summary these changes are acceptable because the revised SR will continue to demonstrate that the EDGs will perform their design functions.

2.2 Background This LAR will increase the availability of the EDGs by eliminating an extra performance of SR 3.8.1.8 in each interval. Currently the EDG manufacturers recommend performance of a maintenance overhaul every 24 months and thus, NSPM schedules Page 2 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension performance of maintenance overhauls for each EDG approximately every 24 months.

SR 3.8.1.8 is performed during each maintenance overhaul. However, it is not possible to perfectly schedule and perform the maintenance on an exact 24 month interval and therefore, the interval may be slightly under or over 24 months. Due to the structure of the PlNGP TS requirements, the current SR 3.8.1.8 Frequency of 24 months does not have any flexibility which would require an additional performance of this SR to meet the TS requirements if the maintenance schedule exceeds 24 months. Since performance of SR 3.8.1.8 requires each EDG to be taken out of service, this additional performance of the SR reduces EDG availability.

With the TS changes proposed in this LAR the plant will continue to operate safely and the health and welfare of the public is protected.

3. TECHNICAL EVALUATION PlNGP is a two unit plant located on the right bank of the Mississippi River approximately 6 miles northwest of the city of Red Wing, Minnesota. The facility is owned and operated by NSPM. Each unit at PlNGP employs a two-loop pressurized water reactor designed and supplied by Westinghouse Electric Corporation. The initial PlNGP application for a Construction Permit and Operating License was submitted to the Atomic Energy Commission (AEC) in April 1967. The Final Safety Analysis Report (FSAR) was submitted for application of an Operating License in January 1971. Unit 1 began commercial operation in December 1973 and Unit 2 began commercial operation in December 1974.

The PlNGP was designed and constructed to comply with NSPM's understanding of the intent of the AEC General Design Criteria (GDC) for Nuclear Power Plant Construction Permits, as proposed on July 10, 1967. PlNGP was not licensed to NUREG-0800, "Standard Review Plan (SRP)."

EDG Description Unit 1 EDGs The Unit 1 EDGs, D l and D2, are Fairbanks-Morse opposed piston EDGs which provide onsite standby power sources for 4 kV safeguards buses 15 and 16. These EDGs are each rated at 2750 kW continuous (8760 hour0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br /> basis), 0.8 power factor, 900 rpm, 4160 Volt, three phase, 60 Hertz, synchronous generators. The 1,000 hour0 days <br />0 hours <br />0 weeks <br />0 months <br /> rating of each EDG is 3000 kilowatts. The 30 minute rating of each unit is 3250 kW maximum.

Unit 2 EDGs The Unit 2 EDGs, D5 and D6, consist of two tandem-drive units (gensets) manufactured by Societe Alsacienne de Constructions Mecaniques de Mulhouse

Enclosure NSPM SR 3.8.1.8 Interval Extension (SACM) which provide onsite standby power sources for 4 kV safeguards buses 25 and

26. These EDGs are each rated at 5400 kW continuous (8760 hour0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br /> basis), 0.8 power factor, 1200 rpm, 4160V, 3-phase, 60 Hertz. Each engine is a SACM UD45 V-16, four-cycle diesel engine, that is, the 5400 kW generator is driven by two V-16 engines which share the load with a common electronic governor system.

Current TS Requirements and Basis SR 3.8.1.8 requires that every 24 months:

Verify each DG's [diesel generator's] automatic trips are bypassed on an actual or simulated safety injection signal except:

a. Engine overspeed;

b. Generator differential current; and

c. Ground fault (Unit 1 only).

The original plant TS did not contain a requirement for testing the EDG bypass relays.

License Amendments 25 and 19, Reference 1, first introduced this requirement for D l and D2, the plant EDGs at that time, to make EDG testing consistent with IEEE-387 (dated March 25, 1972), and NRC EDG test guidance at that time; no reference to specific NRC guidance was provided. The test frequency was every 18 months. The plant was modified in 1992 to power the Unit 1 safeguards buses from D l and D2 and power the Unit 2 safeguards buses from newly installed D5 and D6. License Amendments 103 and 96, Reference 2, revised the TS to include provisions for testing D5 and D6 bypass relays.

The Frequency for this SR was changed from 18 months to 24 months with the conversion to improved TS (ITS), Reference 3. Guidance for PlNGP conversion to ITS was provided in NUREG-1431, "Standard Technical Specifications, Westinghouse Plants" which includes SR 3.0.2 which states:

The specified Frequency for each SR is met if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.

This provision would allow an SR with a specified Frequency of 24 months to be performed at an interval up to 30 months. PlNGP did not adopt this flexibility for SRs with the Frequency specified as 24 months, but rather proposed TS as follows:

The specified Frequency for each SR is met, except for SRs with a specified Frequency of 24 months, if the Surveillance is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.

Page 4 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension The specified Frequency is met for each SR with a specified Frequency of 24 months if the Surveillance is performed within 24 months, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.

The NRC has provided guidance for surveillance interval extension justifications in Generic Letter (GL) 91-04, "Changes in Technical specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle", issued April 2, 1991. To justify SR performance on a 24 month Frequency, justification must be provided for performance at a 30 month interval because of the interval extension normally allowed by SR 3.0.2.

Since the PlNGP pre-ITS included a provision for refueling cycle associated SRs to be performed at 24 months, no further justification was required for most ITS SRs with the specified Frequency of 24 months. As a means to limit resource expenditures during the ITS conversion process, the Nuclear Management Company, LLC (NMC), the plant operating licensee at that time, chose to limit SRs with a 24 month Frequency to a 24 month interval without the SR 3.0.2 interval extension, that is, no additional justification was required under the guidance of GL 91-04 by eliminating the SR 3.0.2 interval extension for these SRs.

In accordance with the EDG manufacturer's recommendations, NSPM schedules a maintenance overhaul for each EDG approximately every 24 months. Performance of SR 3.8.1.8 is included with the maintenance overhaul. However, since it is not possible to precisely perform the overhaul, and SR 3.8.1.8, on a 24 month interval, an additional performance of SR 3.8.1.8 may be required some cycles to meet the TS requirements.

The EDGs have to be declared inoperable to perform this SR which means additional unavailability time for each EDG.

Proposed Changes This LAR proposes to revise the SR 3.8.1.8 Frequency by the addition of a Note which states, "SR 3.0.2 interval extension (1.25 times the interval) applies to this SR". With this change, this SR can be performed at a nominal 24 month interval and no conflict exists with the PlNGP TS SR 3.0.2 requirements.

Technical Basis for Chanqe Although it does not strictly apply to this circumstance, the guidance of GL 91-04 has been applied for justification of extension of the SR 3.8.1.8 Frequency up to 30 months.

The GL identified the following information to support conversion to a 24-month Frequency (30 month interval with SR 3.0.2 interval extension) which is applicable to this LAR:

a. Licensees should evaluate the effect on safety of an increase in the surveillance interval to accommodate a 24-month Frequency (maximum 30 month interval).

This evaluation should support a conclusion that the effect on safety is small.

Page 5 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension

b. Licensee should confirm that historical plant maintenance and surveillance data support this conclusion.

c. Licensee should confirm that assumptions in the plant licensing basis would not be invalidated on the basis of performing any surveillance at the bounding surveillance interval limit provided to accommodate a 24 month Frequency (30 month interval).

During routine operations of the EDGs, there are instrumented indications of potential mechanical engine or electrical failures that can automatically shut down the EDG to protect the engine or generator. When a safety injection (SI) signal or a simulated SI signal is present, a relay is actuated to prevent the EDGs from tripping on the non-critical protective mechanical trips.

SR 3.8.1.8 demonstrates that EDG non-critical protective functions (for example, high jacket water temperature) are bypassed on an actual or simulated SI signal. The non-critical trips are all the automatic trips except for: engine overspeed; generator differential current; and ground fault (Unit 1 EDGs only). The non-critical trips are bypassed during design basis accident (DBAs) and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. EDG availability to mitigate a DBA is more crucial than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the EDG.

Each diesel generator control system has one relay that prevents multiple diesel generator trips during an emergency start which is tested by SR 3.8.1.8. These relays are:

MCNDI, D l DSL GEN AUX RELAY MCND2, D2 DSL GEN AUX RELAY SIMRID5, D5 SAFETY INJECTION MASTER RELAY, and SIMRID6, D6 SAFETY INJECTION MASTER RELAY The coils for these relays are normally in a de-energized state resulting in no degradation to the relay coil due to heating. Instrumentation drift, another consideration addressed in GL 91-04, is not applicable to these relays because they do not have any adjustable settings.

The MCA (Maximum Credible Accident) relays, used on D l and D2, are Clark convertible pole 129VDC relays and are described in Clark Bulletin 7304-PM. The relay operating coil is contained in molded epoxy resin which keeps out dirt and moisture, and withstands physical abuse. In order to change state these relays use a vertical lift to pickup and gravity to dropout. These relays are produced with double break fine silver alloy contacts and are designed to perform a wiping-action to assure contact Page 6 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension reliability. The individual contacts are mounted on poles and separated from each other through the use of a melamine pole housing. This housing forms an insulating barrier between adjacent contact assemblies, so that a short circuit in one contact will not damage the others.

The SlMR (Safety Injection Master Relay) relays, used for D5 and D6, are Arteche RF-4SY style relays with 125VDC coil rating. These relays are constructed with a coil of enameled copper wire wound onto a spool manufactured from fiber glass filled with Phenylene polyoxide (Noryl GFN3SE1). The relay contacts are utilized through a chromium plated hinged armature fitted with nickel-plated contact holders and silver contacts. These relays are designed for: a long continuous life; wide guaranteed margin of operation from cold and hot; metal parts that have been treated against corrosion; and good operation under seismic conditions.

When the EDGs are operating, and an SI signal is present or a functional test of the relay is being performed, the relay coil is energized and the contacts change state.

Opening of the relay contacts blocks the non-critical engine trip signals that would lead to automatic shutdown of the diesel engine.

These relay actuation mechanisms are aged based on the number of times they are cycled. Since these relays are only occasionally cycled and the coils are normally de-energized, the relays will likely outlast the plant. Based on the installation of these relays in a clean and temperature controlled environment, degradation of these relays is not expected. A review of the performance and history of these relays since approximately 1995 did not identify any instances of failures or the need for replacement. Based on the maintenance history and the design of this bypass circuitry, the proposed Frequency Note which would change the allowable maximum interval from 24 months to 30 months will not affect the reliability of the PlNGP EDGs.

Failure of these bypass relays does not directly result in the failure of an EDG to perform its safety function and provide power to the safeguards buses. The EDG will continue to operate unless a non-critical electrical or mechanical trip, a critical electrical or mechanical trip, or the manual emergency-stop signal stops the EDG. The EDGs are tested every month to assure that they operate correctly and therefore it is unlikely that an actual or spurious engine or generator automatic stop signal will actuate.

Thus the single active failure of the bypass relay would not prevent operation of the EDGs during an accident; a second active engine or generator failure would be required in addition to the relay failure to stop the EDG.

Conversely, if a valid non-critical engine trip signal actuated during required emergency operation of the EDG, there is some probability that the malfunction causing the non-critical trip signal would result in EDG shutdown regardless of the proper functioning of the bypass relay. The failure of a single EDG is within the PlNGP design basis; since there are two trains of EDGs, the emergency onsite AC system is designed to continue providing power to a safeguards bus following a single active failure. Allowing the Page 7 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension maximum test interval to be 30 months has minimal affect on the availability of the emergency onsite AC system.

The guidance of GL 91-04 for SR extension to a bounding surveillance interval limit of 30 months is met as follows:

a. The effect on safety of an increase in the surveillance interval to accommodate a 30 month interval was evaluated above and concluded that the effect on safety is small.

b. There have been no identified failures or replacements of these relays; therefore, the historical plant maintenance and surveillance data support this conclusion.

c. The plant licensing basis would not be invalidated on the basis of performing this surveillance at the bounding 30 month interval. If this relay failed to function, the associated EDG would continue to operate unless a second active failure occurs to disable the EDG. The plant design basis continues to provide onsite emergency AC power if a single active failure occurs.

Another consideration addressed in GL 91-04 is instrumentation drift. The bypass relay, activated by an SI or simulated SI signal, is either on or off and does not have any adjustable settings. Therefore instrument drift is not a consideration for this relay.

Based on the guidance of GL 91-04 the Frequency for SR 3.8.1.8 can acceptably be modified by the Frequency Note which would allow the interval extension to 30 months.

This Note in this location is appropriate because application of the SR 3.0.2 interval extension to this SR is an exception to SR 3.0.2. SR 3.0.2 states that, "Exceptions to this Specification are stated in the individual Specifications."

In a public meeting with the NRC on June 10, 2008, the NRC suggested that Risk Informed TS (RITS) Initiative 5b (RITS 5b) guidance be considered for this modification of the SR 3.8.1.8 interval. RITS 5b implementation guidance is provided in Nuclear Energy Institute (NEI) document NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies, Industry Guidance document". NEI 04-10 provides deterministic and risk-informed guidance for modifying SR Frequencies. Since this LAR is not a risk-informed submittal and pursuant to a telephone call with the NRC Staff on December 2, 2008, only the deterministic guidance was considered. Attachment 4 provides an assessment of extending the SR 3.8.1.8 interval to 30 months and concluded that this proposed change is acceptable. In general, these relays have not failed throughout the industry and other plants perform this SR on a 24 month Frequency with the SR 3.0.2 interval extension.

NEI 04-10 recommends that SR Frequency changes be made in small increments to the next standard SR interval rather than making large increases in a single change, for example, if an SR is performed monthly, the next logical Frequency would be to go to quarterly rather than every six months or annually. This proposed change meets this guidance since the change is from 24 months maximum to 24 months with the SR 3.0.2 interval extension allowed.

Enclosure NSPM SR 3.8.1.8 Interval Extension Industry guidance for maintenance on these types of control relays is provided in Electric Power Research Institute (EPRI) TR-102067, Maintenance and Application Guide for Control Relays and Timers, 1993. Section 5 provides some guidance on maintenance philosophies used throughout the industry. While this section does not provide any guidance on the surveillance of components that are required by Technical Specifications, it does provide information used to justify the time requirements for such testing. EPRI TR-102067, Section 5.2.1, Maintenance Philosophy, states:

5.2.1 Maintenance Philosophy Relays are installed to provide control and safety interlock functions. All relays do not arbitrarily require the same level of periodic inspection, testing and maintenance. The maintenance program should include a review of the design basis for each relay or group of relays and the relay's role in the safe and reliable operation of the plant. The following are examples of application differences that should be considered:

Not all relays have equal safety importance. Relays that perform safe shutdown functions or other Class 1E functions certainly require a higher level of reliability than relays providing auxiliary control and alarm functions.

Individual relays may require different maintenance attention because of their locations, environments, or operating status. For example, a normally energized relay located in a room/enclosure with a year-round average temperature greater than 105 OF probably requires closer attention than the same type of relay installed in the control room with a year-round average temperature of 70 OF.

All relays are not alike. Different relay designs have unique degradation and failure modes that should be considered. The maintenance program should treat the following types of relays differently:

- Electromechanical hinged-armature relays

- Electromechanical rotary relays

- Electromechanical Solenoid relays

- Electromechanical or pneumatic timer relays

- Solid state relays and timers Relays with known degradation, e.g., time delay relays susceptible to setpoint drift, and continuously energized relays that have frequent coil or coil bobbin failure because of temperature should receive more detailed inspections so that the effect of the degradation on performance is understood and can be minimized

Enclosure NSPM SR 3.8.1.8 Interval Extension The maintenance program philosophy should be based on ensuring component reliability, not simply instituting maintenance requirements in response to manufacturer's recommendations or industry standards. The basis for any maintenance recommendation and the potential contribution of any maintenance practice to relay reliability should be fully understood.

The particular bullet from this section that would justify extending the surveillance intervals is bullet number four. The relays used in both the MCA and SlMR applications are control relays and are not designed to have a specific time delay. Also, the normal state of these relays is de-energized, ensuring that there is not excessive amounts of heating causing degradation of the coil.

Conclusions This LAR proposes to add a Frequency Note to SR 3.8.1.8, the EDG bypass relay test, to allow application of the SR 3.0.2 interval extension. These relays are very reliable.

They are normally de-energized, located in a mild environment and have a history of performing their function when tested, that is, they do not have a history of failure.

Failure of the bypass relay does not prevent an EDG from performing its safety function. The assessment of proposed revised SR Frequency under the guidance of GL 91-04 concluded that the Frequency can be extended up to 30 months (through application of the interval extension provided in SR 3.0.2). A deterministic assessment under NEI 04-10, the implementation guidance for RlTS 5b, also determined that the proposed Frequency Note is acceptable. Operation and maintenance of the Prairie Island Nuclear Generating Plant with the proposed TS revisions will continue to protect the health and safety of the public.

4. REGULATORY SAFETY ANALYSIS 4.1 Applicable Regulatorv ReauirementslCriteria Title 10 Code of Federal Regulations 50.36, "Technical specifications":

(c) Technical specifications will include items in the following categories:

3 ) Sun/eillance requirements. Surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.

This license amendment request proposes to add a Frequency Note to SR 3.8.1.8 which will allow application of the Surveillance Requirement 3.0.2 interval extension (1.25 times the specified 24 month Frequency) for performance of this surveillance.

This would be an exception to the limitations specified in the Prairie Island Nuclear Generating Plant Technical Specifications Surveillance Requirement 3.0.2 for Page 10of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension Surveillance Requirements with a 24 month Frequency and would allow an interval up to 30 months for performance of the surveillance. These relays are very reliable and a bypass relay failure, by itself, does not prevent an emergency diesel generator from performing its safety function. With these changes, the Technical Specifications will continue to assure that the necessary quality of the emergency diesel generators and their components is maintained and the limiting conditions for operation of these systems will continue to be met.

Thus with the changes proposed in this license amendment request, the requirements of Title 10 CFR 50.36 continue to be met.

General Design Criteria The construction of the Prairie Island Nuclear Generating Plant was significantly complete prior to issuance of 10 CFR 50, Appendix A, General Design Criteria. The Prairie Island Nuclear Generating Plant was designed and constructed to comply with the Atomic Energy Commission General Design Criteria as proposed on July 10, 1967 (AEC GDC) as described in the plant Updated Safety Analysis Report. AEC GDC proposed Criterion 39 provides design guidance for the operating capability of systems to control gaseous radioactive effluents.

Criterion 39 - Emergencv Power For Engineered Safetv Features Alternate power systems shall be provided and designed with adequate independency, redundancy, capacity, and testability to permit the functioning required of the engineered safety features. As a minimum, the onsite power system and the offsite power system shall each, independently, provide this capacity assuming a failure of a single active component in each power system.

AEC GDC Criterion 39 is partially met through the redundant source of emergency power from four emergency diesel generators installed at the plant. This license amendment request proposes changes to the Technical Specifications which will allow application of the Surveillance Requirement 3.0.2 interval extension to the 24 month Frequency which would allow testing the emergency diesel generator relay which bypasses non-critical trips at an interval up to 30 months. With these changes, the AEC GDC stated above will continue to be met when the plant is operated with the plant Technical Specifications revised as proposed. Thus with the changes proposed in this license amendment request, the requirements of AEC GDC 39 continue to be met and the plant Technical Specifications will continue to provide the basis for safe plant operation.

4.2 Precedent Any plant that has the improved Standard Technical Specification Surveillance Requirement 3.0.2 (SR 3.0.2) provisions for interval extensions and has the Frequency for the emergency diesel generator bypass relay Surveillance Requirement set at 24 months has been granted the same interval for performing this surveillance as

Enclosure NSPM SR 3.8.1.8 Interval Extension proposed in this license amendment request. An example plant is the R.E. Ginna Nuclear Power Plant (Ginna) which has the improved Standard Technical Specification SR 3.0.2 provisions for interval extensions and the Frequency for Surveillance Requirement 3.8.1.8, the Ginna Surveillance Requirement which tests the emergency diesel generator bypass relay, is 24 months (Reference 4).

An example of a plant which made this change in a license amendment request subsequent to their conversion to the improved Standard Technical Specifications is provided by the H.B. Robinson Steam Electric Plant, Unit 2 (Robinson), which submitted a license amendment request dated November 30, 2005, Reference 5, to revise the Frequency to 24 months for SR 3.8.1. I 1, the Robinson Surveillance Requirement which tests the emergency diesel generator bypass relay. Since the Robinson plant has the improved Standard Technical Specification SR 3.0.2 provisions for interval extension, the NRC Safety Evaluation dated October 4, 2006, Reference 6, which approved a surveillance testing interval of 24 months is equivalent to the changes requested in this license amendment request.

4.3 Significant Hazards Consideration The Nuclear Management Company has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment," as discussed below:

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

Response: No This license amendment request proposes to add a Frequency Note to Surveillance Requirement 3.8.1.8 which will allow application of the Surveillance Requirement 3.0.2 interval extension (1.25 times the specified 24 month Frequency) for performance of this surveillance. This would be an exception to the limitations specified in the Prairie Island Nuclear Generating Plant Technical Specification Surveillance Requirement 3.0.2 for Surveillance Requirements with a 24 month Frequency and would allow an interval up to 30 months for performance of the surveillance.

The emergency diesel generators are not accident initiators and therefore, these changes do not involve a significant increase the probability of an accident.

Failure of the bypass relay, by itself, does not prevent an emergency diesel generator from performing its safety related functions. Since the accident analyses only require one of the two trains of onsite emergency AC to be operable, the changes proposed in the license amendment request do not involve a significant increase in the consequences of an accident.

Page 12 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

Response: No This license amendment request proposes to add a Frequency Note to Surveillance Requirement 3.8.1.8 which will allow application of the Surveillance Requirement 3.0.2 interval extension (1.25 times the specified 24 month Frequency) for performance of this surveillance. This would be an exception to the limitations specified in the Prairie Island Nuclear Generating Plant Technical Specification Surveillance Requirement 3.0.2 for Surveillance Requirements with a 24 month Frequency and would allow an interval up to 30 months for performance of the surveillance.

The changes proposed for the emergency diesel generators do not change any system operations or maintenance activities. Testing requirements will be revised and will continue to demonstrate that the Limiting Conditions for Operation are met and the system components are functional. The revised test Frequency does not create new failure modes or mechanisms and no new accident precursors are generated.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.

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

Response: No This license amendment request proposes to add a Frequency Note to Surveillance Requirement 3.8.1.8 which will allow application of the Surveillance Requirement 3.0.2 interval extension (1.25 times the specified 24 month Frequency) for performance of this surveillance. This would be an exception to the limitations specified in the Prairie Island Nuclear Generating Plant Technical Specification Surveillance Requirement 3.0.2 for Surveillance Requirements with a 24 month Frequency and would allow an interval up to 30 months for performance of the surveillance.

The proposed change will continue to ensure that the DG trips bypass function operates as designed. The functionality and operability of the emergency power system is not being changed. Since the requested change only allows extension of the relay testing interval and failure of the relay by itself does not prevent the Page 13 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension diesel from performing its safety function, this change does not involve a significant a significant reduction in a margin of safety.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above, the Nuclear Management Company concludes that the proposed amendment does not involve a 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.

4.4 Conclusions In conclusion, based on the considerations discussed in above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5. ENVIRONMENTAL CONSIDERATION A review 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 surveillance requirement. 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(~)(9).Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6. REFERENCES

1. NRC letter dated January 18, 1978, License Amendments 25 and 19, Accession Number ML022170446.

2. Prairie Island Nuclear Generating Plant, Unit Nos. 1 and 2 -Amendment Nos.

103 and 96 to Facility Operating License Nos. DPR-42 and DPR-60 (TAC Nos.

M83070 and M83071), dated December 17, 1992, Accession Number ML022240504.

Page 14 of 15

Enclosure NSPM SR 3.8.1.8 Interval Extension

3. Prairie Island Nuclear Generating Plant, Units 1 and 2, Issuance of Amendments RE: Conversion to Improved Technical Specifications (TAC Nos. MB0695 and MB0696), dated July 26,2002, Accession Numbers ML022070654 and ML022070613.

4. R.E. Ginna, Current Facility Operating License DPR-018, Tech Specs, Revised 10/01/2007, Accession Number ML052720231.

5. H.B Robinson, Unit 2 - Request for Technical Specifications Change to Section 3.8.1 for the Diesel Generator Automatic Trips Bypass, dated November 30, 2005, Accession Number ML053410437.

6. H.B. Robinson, Unit 2, License Amendment 208 regarding Emergency Diesel Generator or Automatic Trip Bypass TS 3.8.1, dated October 4, 2006, Accession Number ML062130637.

Page 15 of 15

ENCLOSURE, ATTACHMENT 1 Technical Specification Pages (Markup) 3.8.1-8 1 page follows

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.6 ............................ NOTE ...........................

All DG starts may be preceded by an engine prelube period.

Verify each DG starts from standby condition and 184 days achieves:

a. In 5 10 seconds, voltage 2 3740 V and frequency > 58.8 Hz; and

b. >

Steady state voltage 3740 V and 5 4580 V, and frequency > 58.8 Hz and 5 6 1.2 Hz.

SR 3.8.1.7 Verify each DG does not trip during and following a 24 months load rejection of:

1. Unit 1 > 650 kW; and

2. Unit 2 > 860 kW.

SR 3.8.1.8 Verify each DG's automatic trips are bypassed on an actual or simulated safety injection signal except: SR 3.0.2 interval extension ( 1.25

a. Engine overspeed; times the interval) applies

b. Generator differential current; and to this SR

c. Ground fault (Unit 1 only).

24 months Prairie Island Unit 1 - Amendment No. 4-58 Units 1 and 2 Unit 2 - Amendment No. 149

ENCLOSURE, ATTACHMENT 2 Bases Pages (Markup)

(For Information Only) 2 pages follow

SR Applicability B 3.0 BASES SR 3.0.2 ongoing Surveillance or maintenance activities).

(continued)

The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency.

This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the SRs. The exceptions to SR 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply. These exceptions are stated in the individual Specifications. The requirements of regulations take precedence over the TS. An example of where SR 3.0.2 does not apply is in the Containment Leakage Rate Testing Program. This program establishes testing requirements and Frequencies in accordance with the requirements of regulations. The TS cannot in and of themselves extend a test interval specified in the regulations.

As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per " basis. The 25% extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of hnction has occurred by checking the status of redundant or diverse components or accomplishes the function of the inoperable equipment in an alternative manner.

Also, as stated in SR 3.0.2, the 25% extension does not apply to SRs with a specified Frequency of 24 months unless applicability of SK 3.0.2 is specified in the SR Frequency. This is to ensure performance is within equipment performance expectations. This is consistent with present industry analysis that supports reheling cycle intervals up to, but not longer than, 24 months.

The provisions of SR 3.0.2 are not intended to be used repeatedly merely as an operational convenience to extend Surveillance Prairie Island Unit 1 - Revision 4-?6 IJnits 1 and 2 Unit 2 - Revision-4-76

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE SR 3.8.1.8 (continued)

REQ-The noncritical trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the I

operator with sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

The Frequency is modified by a Note which allows the SR 3.0.2 interval extension ( 1.25 times the specified interval) to be applied to the interval for this SK, that is, this SR inay be performed at an interval up to 30 months within the guidance of SR 3.0.2 for interval extensions. This is an exception to the limitations stated in SR 3.0.2 for SKs with a 24 month Frequency. The 24 month Frequency is based on engineering judgment, taking into consideration unit conditions required to the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

Demonstrate once per 24 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, 2 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> of which is at a load equivalent to 103 - 110% of the continuous duty rating and the remainder of the time at a load equivalent to the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelubricating and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

Prairie Island Unit 1 - Revision 1-38 Units I and 2 Unit 2 - Revision 1-38

ENCLOSURE, ATTACHMENT 3 Technical Specification Pages (Retyped) 3.8.1-8 1 page follows

AC Sources-Operating 3.8.1 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 3.8.1.6 ............................ NOTE ...........................

All DG starts may be preceded by an engine prelube period.

VerifL each DG starts from standby condition and 184 days achieves:

a. In 5 10 seconds, voltage 2 3740 V and frequency 2 58.8 Hz; and

b. Steady state voltage 2 3740 V and 5 4580 V, and frequency 2 58.8 Hz and < 61.2 Hz.

SR 3.8.1.7 VeriQ each DG does not trip during and following a 24 months load rejection of:

1. Unit 1 2 650 kW; and

2. Unit 2 2 860 kW.

SR 3.8.1.8 Verifj each DG's automatic trips are bypassed on an -------NOTE------

actual or simulated safety injection signal except: SR 3.0.2 interval extension (1.25

a. Engine overspeed; times the interval) applies

b. Generator differential current; and to this SR

c. Ground fault (Unit 1 only).

24 months Prairie Island Unit 1 - Amendment No. 458 Units 1 and 2 Unit 2 - Amendment No. 4-49

Attachment 4 to Enclosure Application of Nuclear Energy Institute (NEI) 04-10 Guidance Document to Surveillance Requirement (SR) 3.8.1.8 interval extension In a public meeting with the Nuclear Regulatory Commission (NRC) on June 10, 2008, the NRC suggested that Risk Informed TS (RITS) Initiative 5b (RITS 5b) guidance be considered for this modification of the SR 3.8.1.8 interval. Since this license amendment request (LAR) is not a risk-informed submittal and pursuant to a telephone call with the NRC Staff on December 2, 2008, only the deterministic guidance provided in NEI 04-10 was considered.

Each diesel generator control system has one relay that prevents multiple diesel generator trips during an emergency start which is tested by SR 3.8.1.8. These relays are:

MCNDI, D l DSL GEN AUX RELAY MCND2, D2 DSL GEN AUX RELAY SIMRIDS, D5 SAFETY INJECTION MASTER RELAY, and SIMRID6, D6 SAFETY INJECTION MASTER RELAY The MCA (Maximum Credible Accident) relays, used on D l and D2, are Clark convertible pole 129VDC relays. The SlMR (Safety Injection Master Relay) relays, used for D5 and D6, are Arteche RF-4SY style relays.

Step 0: Select Proposed Surveillance Test Intervals (STls) for Adjustment The deterministic elements of this methodology are to be applied to SR 3.8.1.8 in support of an LAR to apply the SR 3.0.2 interval extension which would allow the interval to be extended up to 30 months.

Step 1: Check for Prohibitive Commitments The requirement to test the emergency diesel generator (EDG) bypass relay was incorporated into TS by License Amendments 25 and 19 for D l and D2 and 103 and 96 for D5 and D6. No commitments have been identified for this test or the bypass relays and thus the interval for SR 3.8.1.8 can be changed without a commitment change.

Step 2: Can Commitments be Changed As noted in Step 1, no commitments have been identified for this test or the relays. This Step is not applicable.

Page 1 of 5 NEI 04-10 Step 3: Change the Commitments As noted in Step 1, no commitments have been identified for this test or the relays. This Step is not applicable.

Step 4: Document that ST1 Changes Cannot be Changed This Step applies to an NRC commitment to a specific ST1 that cannot be changed without prior NRC approval. As noted in Step 1, no commitments have been identified for this test or the relays. This Step is not applicable.

Step 5: RG 1.200 PRA Technical Adequacy Not applicable per discussion with the NRC Staff.

Step 6: Select Desired Revised ST1 Values The proposed surveillance test interval is 24 months with the SR 3.0.2 interval extension of 1.25 times the specified interval. Thus the maximum interval is 30 months.

Step 7: Identify Qualitative Considerations to be Addressed Surveillance test and performance history of the components and system associated with the ST1 adjustment.

A review of bypass relay test results since 1995 did not identify any failures.

Past industry and plant-specific experience with the functions affected by the proposed changes.

A search of industry operating experience has found the only reported failures of Clark PM style DC relays at Crystal River Nuclear Generating Station Unit 3 in 1999 and at the Zion Nuclear Power Station in 1991. No record of Arteche RF-4SY style relays failing has been found.

Impact on defense-in-depth protection.

The proposed interval change does not affect defense-in-depth protection. The proposed interval will identify failures on a timely basis. Failure of this relay does not prevent the associated EDG from performing its safety function and there are two trains of EDGs to allow for a single active failure.

Vendor-specified maintenance frequency.

The relay vendors do not recommend replacement or maintenance of the bypass relays. The manufacturer of the Unit 1 emergency diesel generators Page 2 of 5 NEI 04-10 recommends a check of safety and shutdown controls for proper setting and operation each refueling cycle. The checks include the site specific engine trips, emergency trips, emergency stop pushbutton and the overspeed trip. The manufacturer recognizes that the engine trips are checked with each preventive maintenance. Since the bypass relay is not an engine trip, the manufacturer does not have any recommendations which specifically address checking this relay.

Test intervals specified in applicable industry codes and standards, e.g., ASME, IEEE, etc.

o Document that a review of both the committed and current version of applicable industry codes and standards was performed.

No specific test intervals were identified in industry codes and standards.

General industry guidance on these types of control relays is provided in Electric Power Research Institute (EPRI) TR-102067, "Maintenance and Application Guide for Control Relays and Timers", 1993. Section 5 provides some guidance on maintenance philosophies used throughout the industry. Table 5-1, "Recommended Inspection, Test and Maintenance for Relays in General",

provides general guidance that relays which are not covered by Technical Specification Surveillance Requirements should be tested annually. Section 5.2.1, "Maintenance Philosophy", provides further guidance as follows:

5.2.1 Maintenance Philosophy Relays are installed to provide control and safety interlock functions. All relays do not arbitrarily require the same level of periodic inspection, testing and maintenance. The maintenance program should include a review of the design basis for each relay or group of relays and the relay's role in the safe and reliable operation of the plant. The following are examples of application differences that should be considered:

Relays with known degradation, e.g., time delay relays susceptible to setpoint drift, and continuously energized relays that have frequent coil or coil bobbin failure because of temperature should receive more detailed inspections so that the effect of the degradation on performance is understood and can be minimized The maintenance program philosophy should be based on ensuring component reliability, not simply instituting maintenance requirements in response to manufacturer's recommendations or industry standards. The basis for any maintenance recommendation and the potential contribution of any maintenance practice to relay reliability should be fully understood.

Page 3 of 5 NEI 04-10 The bulleted paragraph from this section quoted above would justify extending the surveillance intervals. The relays used in both the MCA and SlMR applications are control relays and are not designed to have a specific time delay. Also, the normal state of these relays is de-energized, ensuring that there is not excessive amounts of heating causing degradation of the coil.

o Any deviations from STls specified in applicable industry codes and standards currently committed to in the plant licensing basis shall be reviewed and documented consistent with the considerations specified within this step (Step 7).

NSPM has not identified any deviation from STls specified in applicable industry codes and standards currently committed to in the plant licensing basis.

Impact of a SSC in an adverse or harsh environment.

The bypass relays are located in a mild environment and are not exposed to post accident environments, thus there is no adverse or harsh environment impact.

Benefits of detection at an early stage of potential mechanisms and degradations that can lead to common cause failures.

The bypass relay does not lead to common cause failure of the EDG since its failure does not prevent the EDG from performing its safety function. There are no compounding effects of failure to identify bypass relay failure, thus there are no significant benefits to early detection of relay failure.

Document that assumptions in the plant licensing basis would not be invalidated when performing the surveillance at the bounding interval limit for the proposed ST1 change. For example, if the assumptions in the plant licensing basis would be invalidated at the bounding STI, the ST1 could be limited accordingly or a more conservative acceptance criteria could be established, as appropriate.

The licensing basis for the on-site standby power system is that two trains are provided to assure that a single failure will not cause a loss of on-site power.

Since failure of a bypass relay does not prevent an EDG from performing its safety function, allowing the surveillance interval for the bypass relays to be extended up to 30 months does not invalidate the licensing basis assumptions.

The degree to which the surveillance provides a conditioning exercise to maintain equipment operability, for example, lubrication of bearings or electrical contact wiping (cleaning) of built up oxidation, and limit the ST1 accordingly.

Performance of the bypass relay surveillance does not provide any conditioning of other equipment.

Page 4 of 5 NEI 04-10 The existence of alternate testing of systems, structures and components (SSCs) affected by the ST1 change.

Extension of the bypass relay test interval does not impact any other EDG tests.

Each month the EDGs are tested to assure that they operate and are not shut down by one of the protective trips that the bypass relay bypasses. This further assures that a failure of the bypass relay will not prevent an EDG from performing its safety function.

The qualitative considerations of Step 7 provide a basis for extending the test interval for the EDG bypass relays in SR 3.8.1.8. No conditions were identified that would indicate the bypass relay should not be tested at a longer interval.

NEI 04-10 Section 4.0, Steps 8 through 14 are related to probabilistic risk assessment and thus are not applicable to this license amendment request.

NEI 04-10 Section 4.0, Steps 15 through 20 are related to elements of a Surveillance Frequency Control Program (SFCP) which are not applicable to this license amendment request since the Prairie Island Nuclear Generating Plant does not have an NRC approved SFCP.

Conclusions The evaluation for each step of this ST1 change process concluded that the interval for the bypass relays in SR 3.8.1.8 can be changed. The proposed change to allow use of the SR 3.0.2 interval extension is consistent with the guidance of NEI 04-10 which recommends that ST1 increases be taken to the next logical longer interval. The next logical increase in the interval from 24 months would be to 24 months with the SR 3.0.2 interval extension to 30 months.

Page 5 of 5