Biweekly Notices UNITED STATES NUCLEAR REGULATORY COMMISSION

Federal RegisterAug 17, 1994

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[Federal Register Volume 59, Number 158 (Wednesday, August 17, 1994)]

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[Federal Register: August 17, 1994]

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Part II

Nuclear Regulatory Commission

_______________________________________________________________________

Operating Licenses, Amendments; No Significant Hazards Considerations;

Biweekly Notices

UNITED STATES NUCLEAR REGULATORY COMMISSION

Biweekly Notice

Applications and Amendments to Facility Operating LicensesInvolving

No Significant Hazards Considerations

I. Background

Pursuant to Public Law 97-415, the U.S. Nuclear Regulatory

Commission (the Commission or NRC staff) is publishing this regular

biweekly notice. Public Law 97-415 revised section 189 of the Atomic

Energy Act of 1954, as amended (the Act), to require the Commission to

publish notice of any amendments issued, or proposed to be issued,

under a new provision of section 189 of the Act. This provision grants

the Commission the authority to issue and make immediately effective

any amendment to an operating license upon a determination by the

Commission that such amendment involves no significant hazards

consideration, notwithstanding the pendency before the Commission of a

request for a hearing from any person.

This biweekly notice includes all notices of amendments issued, or

proposed to be issued from July 25, 1994, through August 5, 1994. The

last biweekly notice was published on August 3, 1994.

Notice Of Consideration Of Issuance Of Amendments To Facility

Operating Licenses, Proposed No Significant Hazards Consideration

Determination, And Opportunity For A Hearing

The Commission has made a proposed determination that the following

amendment requests involve no significant hazards consideration. Under

the Commission's regulations in 10 CFR 50.92, this means that operation

of the facility in accordance with the proposed amendment would not (1)

involve a significant increase in the probability or consequences of an

accident previously evaluated; or (2) create the possibility of a new

or different kind of accident from any accident previously evaluated;

or (3) involve a significant reduction in a margin of safety. The basis

for this proposed determination for each amendment request is shown

below.

The Commission is seeking public comments on this proposed

determination. Any comments received within 30 days after the date of

publication of this notice will be considered in making any final

determination.

Normally, the Commission will not issue the amendment until the

expiration of the 30-day notice period. However, should circumstances

change during the notice period such that failure to act in a timely

way would result, for example, in derating or shutdown of the facility,

the Commission may issue the license amendment before the expiration of

the 30-day notice period, provided that its final determination is that

the amendment involves no significant hazards consideration. The final

determination will consider all public and State comments received

before action is taken. Should the Commission take this action, it will

publish in the Federal Register a notice of issuance and provide for

opportunity for a hearing after issuance. The Commission expects that

the need to take this action will occur very infrequently.

Written comments may be submitted by mail to the Rules Review and

Directives Branch, Division of Freedom of Information and Publications

Services, Office of Administration, U.S. Nuclear Regulatory Commission,

Washington, DC 20555, and should cite the publication date and page

number of this Federal Register notice. Written comments may also be

delivered to Room 6D22, Two White Flint North, 11545 Rockville Pike,

Rockville, Maryland from 7:30 a.m. to 4:15 p.m. Federal workdays.

Copies of written comments received may be examined at the NRC Public

Document Room, the Gelman Building, 2120 L Street, NW., Washington, DC

20555. The filing of requests for a hearing and petitions for leave to

intervene is discussed below.

By September 16, 1994, the licensee may file a request for a

hearing with respect to issuance of the amendment to the subject

facility operating license and any person whose interest may be

affected by this proceeding and who wishes to participate as a party in

the proceeding must file a written request for a hearing and a petition

for leave to intervene. Requests for a hearing and a petition for leave

to intervene shall be filed in accordance with the Commission's ``Rules

of Practice for Domestic Licensing Proceedings'' in 10 CFR Part 2.

Interested persons should consult a current copy of 10 CFR 2.714 which

is available at the Commission's Public Document Room, the Gelman

Building, 2120 L Street, NW., Washington, DC 20555 and at the local

public document room for the particular facility involved. If a request

for a hearing or petition for leave to intervene is filed by the above

date, the Commission or an Atomic Safety and Licensing Board,

designated by the Commission or by the Chairman of the Atomic Safety

and Licensing Board Panel, will rule on the request and/or petition;

and the Secretary or the designated Atomic Safety and Licensing Board

will issue a notice of a hearing or an appropriate order.

As required by 10 CFR 2.714, a petition for leave to intervene

shall set forth with particularity the interest of the petitioner in

the proceeding, and how that interest may be affected by the results of

the proceeding. The petition should specifically explain the reasons

why intervention should be permitted with particular reference to the

following factors: (1) the nature of the petitioner's right under the

Act to be made a party to the proceeding; (2) the nature and extent of

the petitioner's property, financial, or other interest in the

proceeding; and (3) the possible effect of any order which may be

entered in the proceeding on the petitioner's interest. The petition

should also identify the specific aspect(s) of the subject matter of

the proceeding as to which petitioner wishes to intervene. Any person

who has filed a petition for leave to intervene or who has been

admitted as a party may amend the petition without requesting leave of

the Board up to 15 days prior to the first prehearing conference

scheduled in the proceeding, but such an amended petition must satisfy

the specificity requirements described above.

Not later than 15 days prior to the first prehearing conference

scheduled in the proceeding, a petitioner shall file a supplement to

the petition to intervene which must include a list of the contentions

which are sought to be litigated in the matter. Each contention must

consist of a specific statement of the issue of law or fact to be

raised or controverted. In addition, the petitioner shall provide a

brief explanation of the bases of the contention and a concise

statement of the alleged facts or expert opinion which support the

contention and on which the petitioner intends to rely in proving the

contention at the hearing. The petitioner must also provide references

to those specific sources and documents of which the petitioner is

aware and on which the petitioner intends to rely to establish those

facts or expert opinion. Petitioner must provide sufficient information

to show that a genuine dispute exists with the applicant on a material

issue of law or fact. Contentions shall be limited to matters within

the scope of the amendment under consideration. The contention must be

one which, if proven, would entitle the petitioner to relief. A

petitioner who fails to file such a supplement which satisfies these

requirements with respect to at least one contention will not be

permitted to participate as a party.

Those permitted to intervene become parties to the proceeding,

subject to any limitations in the order granting leave to intervene,

and have the opportunity to participate fully in the conduct of the

hearing, including the opportunity to present evidence and cross-

examine witnesses.

If a hearing is requested, the Commission will make a final

determination on the issue of no significant hazards consideration. The

final determination will serve to decide when the hearing is held.

If the final determination is that the amendment request involves

no significant hazards consideration, the Commission may issue the

amendment and make it immediately effective, notwithstanding the

request for a hearing. Any hearing held would take place after issuance

of the amendment.

If the final determination is that the amendment request involves a

significant hazards consideration, any hearing held would take place

before the issuance of any amendment.

A request for a hearing or a petition for leave to intervene must

be filed with the Secretary of the Commission, U.S. Nuclear Regulatory

Commission, Washington, DC 20555, Attention: Docketing and Services

Branch, or may be delivered to the Commission's Public Document Room,

the Gelman Building, 2120 L Street, NW., Washington DC 20555, by the

above date. Where petitions are filed during the last 10 days of the

notice period, it is requested that the petitioner promptly so inform

the Commission by a toll-free telephone call to Western Union at 1-

(800) 248-5100 (in Missouri 1-(800) 342-6700). The Western Union

operator should be given Datagram Identification Number N1023 and the

following message addressed to (Project Director): petitioner's name

and telephone number, date petition was mailed, plant name, and

publication date and page number of this Federal Register notice. A

copy of the petition should also be sent to the Office of the General

Counsel, U.S. Nuclear Regulatory Commission, Washington, DC 20555, and

to the attorney for the licensee.

Nontimely filings of petitions for leave to intervene, amended

petitions, supplemental petitions and/or requests for a hearing will

not be entertained absent a determination by the Commission, the

presiding officer or the Atomic Safety and Licensing Board that the

petition and/or request should be granted based upon a balancing of

factors specified in 10 CFR 2.714(a)(1)(i)-(v) and 2.714(d).

For further details with respect to this action, see the

application for amendment which is available for public inspection at

the Commission's Public Document Room, the Gelman Building, 2120 L

Street, NW., Washington, DC 20555, and at the local public document

room for the particular facility involved.

Arizona Public Service Company, et al., Docket Nos. STN 50-528, STN

50-529, and STN 50-530, Palo Verde Nuclear Generating Station, Unit

Nos. 1, 2, and 3, Maricopa County, Arizona

Date of amendment requests: May 4, 1994

Description of amendment requests: These amendment requests would

revise Limiting Condition for Operation (LCO) 3.4.8.3 and Surveillance

Requirement 4.4.8.3.1, ``Overpressure Protection Systems.''

Specifically, the LCO and surveillance requirements are revised to

clarify that both shutdown cooling system (SCS) suction line relief

valves shall be OPERABLE and aligned to provide overpressure protection

not only during reactor (RCS) cooldown or heatup evolutions, but also

during any steady state temperature periods maintained in the course of

RCS cooldown or heatup evolutions.

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensees have

provided their analysis about the issue of no significant hazards

consideration, which is presented below:

Standard 1 -- Involve a significant increase in the probability

or consequence of an accident previously evaluated.

The proposed amendments provide further clarification of the

Technical Specifications and represent an additional operating

limitation. Incorporating the noted clarification will not change

the bases or assumptions contained in the safety analysis for this

system. The most limiting low-temperature overpressure protection

(LTOP) transients, the starting of an idle reactor coolant pump

(RCP) and the inadvertent actuation of two high pressure safety

injection (HPSI) pumps into a solid RCS, are not affected by the

proposed clarification. Therefore, the proposed amendments do not

involve a significant increase in the probability or consequences of

an accident previously evaluated.

Standard 2 -- Create the possibility of a new or different kind

of accident from any accident previously evaluated.

Clarifying the applicability of the LCO's and surveillance for

steady state periods achieved and maintained during either a heatup

or cooldown evolution does not modify the design or operation of

plant equipment. No new or different failure modes will be

introduced by incorporating this clarification into the LCO and

surveillance requirement. Therefore, the proposed amendments will

not create the possibility of a new or different kind of accident

from any accident previously evaluated.

Standard 3 -- Involve a significant reduction in a margin of

safety.

The clarification will enhance LCO 3.4.8.3 and Surveillance

Requirement 4.4.8.3.1 for heatup and cooldown evolutions by ensuring

operators are aware of this applicability during periods of steady

state conditions. This clarification does not involve a change to

safety limits, setpoints, or design margins. As such, the proposed

amendments will not involve a significant reduction in a margin of

safety at PVNGS.

The NRC staff has reviewed the licensees' analysis and, based on

that review, it appears that the three standards of 50.92(c) are

satisfied. Therefore, the NRC staff proposes to determine that the

amendment requests involve no significant hazards consideration.

Local Public Document Room location: Phoenix Public Library, 12

East McDowell Road, Phoenix, Arizona 85004

Attorney for licensees: Nancy C. Loftin, Esq., Corporate Secretary

and Counsel, Arizona Public Service Company, P.O. Box 53999, Mail

Station 9068, Phoenix, Arizona 85072-3999

NRC Project Director: Theodore R. Quay

Arizona Public Service Company, et al., Docket Nos. STN 50-528, STN

50-529, and STN 50-530, Palo Verde Nuclear Generating Station, Unit

Nos. 1, 2, and 3, Maricopa County, Arizona

Date of amendment requests: June 17, 1994

Description of amendment requests: The proposed amendments would

increase the minimum nitrogen accumulator pressure for the atmospheric

dump valves (ADVs), as stated in the surveillance requirements of

Technical Specification (TS) 3/4.7.1.6. The change to the Bases

increases the minimum time the ADV accumulators must be operable.

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensees have

provided their analysis about the issue of no significant hazards

consideration, which is presented below:

Standard 1 -- Involve a significant increase in the probability

or consequences of an accident previously evaluated.

The proposed Technical Specification change in the nitrogen

accumulator supply minimum pressure will not increase the

probability or consequences of any accident previously analyzed. The

nitrogen accumulator pressure is normally maintained between 650-680

psig. Nitrogen pressure from the accumulator is reduced to 105 psig

prior to use in the operation of the ADVs. The pressure reduction

will remain the same with the higher minimum accumulator pressure.

Standard 2 -- Create the possibility of a new or different kind

of accident from any accident previously evaluated.

Increasing the nitrogen accumulator minimum pressure does not

create any new or different accidents than those previously

evaluated. The normal air supply (the Instrument Air System) to the

ADV is maintained between 105 to 125 psig. Currently, nitrogen from

the accumulator is reduced to 105 psig prior to use in the ADV. The

increased minimum pressure in the accumulator will still be reduced

to 105 psig prior to use in the ADV.

Standard 3 -- Involve a significant reduction in a margin of

safety.

The limitation on maintaining the nitrogen accumulator at a

certain pressure is to ensure that a sufficient volume of nitrogen

is in the accumulator to operate the associated ADV. Maintaining a

higher minimum pressure ensures that sufficient nitrogen will be

available to maintain the unit at HOT STANDBY for four hours and an

additional 9.3 hours to reach COLD SHUTDOWN under natural

circulation conditions in the event of failure of the normal control

air system. Therefore, the proposed change does not involve a

reduction in a margin of safety.

The NRC staff has reviewed the licensees' analysis and, based on

that review, it appears that the three standards of 50.92(c) are

satisfied. Therefore, the NRC staff proposes to determine that the

amendment requests involve no significant hazards consideration.

Local Public Document Room location: Phoenix Public Library, 12

East McDowell Road, Phoenix, Arizona 85004

Attorney for licensees: Nancy C. Loftin, Esq., Corporate Secretary

and Counsel, Arizona Public Service Company, P.O. Box 53999, Mail

Station 9068, Phoenix, Arizona 85072-3999

NRC Project Director: Theodore R. Quay

Arizona Public Service Company, et al., Docket Nos. STN 50-528, STN

50-529, and STN 50-530, Palo Verde Nuclear Generating Station, Unit

Nos. 1, 2, and 3, Maricopa County, Arizona

Date of amendment requests: July 12, 1994

Description of amendment requests: The proposed amendment would

enhance the PVNGS Technical Specifications (TS) by adding a limiting

condition for operation (LCO) action statement to Entry VIII B of Table

3.3-3, ``Engineered Safety Features Actuation System Instrumentation.''

The proposed action statement would enhance safe plant operation by

requiring timely plant shutdown if more than one of the new solid state

degraded voltage relays in either train of 4.16kV are inoperable or not

energized.

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensees have

provided their analysis about the issue of no significant hazards

consideration, which is presented below:

Standard 1--Involve a significant increase in the probability or

consequence of an accident previously evaluated:

The proposed amendment will add an action statement to TS Table

3.3-3 entry VIII B which would allow eight hours to effect repairs.

This action statement would be entered if more than one of the

required four degraded voltage relays on either 4.16 kv bus is

inoperable or not energized. If the eight hour allowed outage time

is not met, the unit is placed in Hot Standby within six hours and

in Cold Shutdown within the next thirty hours. Technical

Specification 3.8.3.1 currently allows eight hours to restore a 4.16

kv bus in the event of a loss of power to that bus. The loss of

degraded voltage relays on that bus does not impact plant nuclear

safety any more than the loss of the bus itself. Furthermore, even

with the loss of all four degraded voltage relays monitoring one

4.16 kv bus (for example, due to a blown 125 vdc circuit fuse), the

loss-of-voltage relays on that bus, and the degraded voltage relays,

as well as the loss-of-voltage relays monitoring the other bus would

be unaffected. None of the UFSAR chapter 15 accident analyses are

affected by this proposed amendment. The existing TS requirements

and those components to which they apply are not altered by this TS

amendment. There are no changes to the maintenance, surveillance,

and/or qualification of any component/function in Table 3.3-3.

Therefore, the addition of this proposed eight hour action statement

to Table 3.3-3 entry VIII B does not increase the probability of

occurrence or the consequences of any previously evaluated accident.

Standard 2--Create the possibility of a new or different kind of

accident from any accident previously evaluated:

The TS requirements and the components to which they apply are

not altered by this amendment. The new solid state degraded voltage

relays in each 4.16 kv bus were installed under the 10 CFR 50.59

change process. APS [Arizona Public Service Company] determined that

the installation created no unreviewed safety question. This

amendment has no impact on plant maintenance, testing, shutdown

equipment, or component qualification. Plant operational safety is

enhanced by this amendment. Therefore, the possibility of a new or

different kind of accident is not created by this amendment.

Standard 3--Involve a significant reduction in a margin of

safety:

The TS does not alter existing TS requirements or those

components to which they apply. More specifically, there is no

impact on safe plant shutdown, maintenance, containment isolation

capability, containment leakage rate, or the operability of safety

related valves. Therefore, the addition of the proposed action

statement to the TS will not involve reduction in a margin of safety

for fission product release to the atmosphere.

The NRC staff has reviewed the licensees' analysis and, based on

that review, it appears that the three standards of 50.92(c) are

satisfied. Therefore, the NRC staff proposes to determine that the

amendment requests involve no significant hazards consideration.

Local Public Document Room location: Phoenix Public Library, 12

East McDowell Road, Phoenix, Arizona 85004

Basis for proposed no significant hazards consideration

determination:

Attorney for licensees: Nancy C. Loftin, Esq., Corporate Secretary

and Counsel, Arizona Public Service Company, P.O. Box 53999, Mail

Station 9068, Phoenix, Arizona 85072-3999

NRC Project Director: Theodore R. Quay

Baltimore Gas and Electric Company, Docket Nos. 50-317 and 50-318,

Calvert Cliffs Nuclear Power Plant, Unit Nos. 1 and 2, Calvert

County, Maryland

Date of amendments request: June 8, 1994

Description of amendments request: The proposed amendment would

revise the Calvert Cliffs Nuclear Power Plant (CCNPP) Units 1 and 2

Technical Specification (TS) Section 4.7.1.2.c to extend the interval

for three Auxiliary Feedwater (AFW) surveillance requirements from 18

to 24 months. Specifically, TS Section 4.7.2.c.1 requires the

verification of each automatic valve in the flowpath actuate to its

correct position and each AFW pump automatically start upon receipt of

each AFW actuation system test signal; TS Section 4.7.2.c.2 requires

verification that the AFW system is capable of providing a minimum 300

gallons per minute nominal flow to each leg. This request is one of a

series of proposed license amendments that would eliminate the need for

mid-cycle surveillance outages by extending 18-month frequency

surveillances to every refueling outage (nominally each 24 months).

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensee has

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

1. Would not involve a significant increase in the probability

or consequences of an accident previously evaluated.

The Auxiliary Feedwater (AFW) System provides a safety-related

source of feedwater to the steam generators to mitigate design basis

accidents involving loss of Main Feedwater. Failure of the AFW

System is not an initiator for any previously analyzed accident.

Therefore, the proposed change does not involve an increase in the

probability of an accident previously evaluated.

A historical review of surveillance test results and system

performance indicates that the AFW System is very reliable. In

addition, monthly surveillances of the AFW System will continue to

verify proper pump and valve operation. The AFW System reliability

and monthly surveillances provide assurance that undetected system

degradation will not occur between 24-month surveillances.

Therefore, the AFW System will continue to perform its safety

function and there will be no significant increase in the

consequences of accidents. Therefore, the proposed Technical

Specification changes do not increase the probability or

consequences of an accident previously evaluated.

2. Would not create the possibility of a new or different type

of accident from any accident previously evaluated?

This requested revision to increase the interval for some AFW

surveillances from 18 to 24 months does not involve a significant

change in the design or operation of the plant. No hardware is being

added to the plant as part of the proposed change. The proposed

change will not introduce any new accident initiators. Therefore,

this change would not create the possibility of a new or different

type of accident from any accident previously evaluated.

3. Does operation of the facility in accordance with the

proposed amendment involve a significant reduction in a margin of

safety?

The AFW System provides a margin of safety by providing a

safety-related alternate supply of feedwater to the steam generator

for removal of decay heat and cooldown of the Reactor Coolant

System. The proposed changes do not affect the operation or design

of the AFW System. Monthly surveillances and historical data provide

assurance that the reduction in surveillance frequency will not

adversely affect our ability to detect degradation in the system.

Therefore, the proposed change does not involve a significant

reduction in a margin of safety.

The NRC staff has reviewed the licensee's analysis and, based on

this review, it appears that the three standards of 50.92(c) are

satisfied.Therefore, the NRC staff proposes to determine that the

amendments request involves no significant hazards consideration.

Local Public Document Room location: Calvert County Library, Prince

Frederick, Maryland 20678.

Attorney for licensee: Jay E. Silbert, Esquire, Shaw, Pittman,

Potts and Trowbridge, 2300 N Street, NW., Washington, DC 20037.

NRC Project Director: Michael L. Boyle

Consolidated Edison Company of New York, Docket No. 50-247, Indian

Point Nuclear Generating Unit No. 2, Westchester County, New York

Date of amendment request: April 29, 1994

Description of amendment request: This amendment is an additional

followup to the amendment request of May 29, 1992, published in the

Federal Register on July 8, 1992 (57FR30242), which changed the

Technical Specifications Section 1.0, Definitions, to accommodate a 24-

month fuel cycle and which proposed the extension of the test intervals

for specific surveillance tests. This amendment proposes extending the

surveillance intervals to 24 months for the following additional

surveillance tests:(1) Calibrate and test channels for Auxiliary

Feedwater (AFW) initiation on steam generator water level (low-low).(2)

Test channels for Auxiliary Feedwater initiation on trip of main

feedwater pumps.The licensee's amendment proposal of November 25, 1992,

requested approval for extending the surveillance interval of the

Auxiliary Feedwater System to accommodate a 24-month fuel cycle and the

approved change was issued in License Amendment No. 166. Subsequently,

the licensee determined that two additional surveillances associated

with this system had not been identified in the November 25, 1992,

request. This amendment proposal requests approval of the additional

surveillances. The changes requested by the licensee are in accordance

with Generic Letter 91-04, ``Changes in Technical Specification

Surveillance Intervals to Accommodate a 24-Month Fuel Cycle.''

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensee has

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

The proposed change does not involve a significant hazards

consideration since:

1. There is no significant increase in the probability or

consequences of an accident.

The test results over the last four refuelings confirmed system

operability with only one failure. This failure would not have

impaired the ability of the auxiliary feedwater system to perform

its intended safety function. The auxiliary feedwater system is

redundant and diverse. The failure in the turbine driven pump did

not impact the motor driven pumps.

Based on the historical test data, it is concluded that no

significant increase in the probability or consequences of an

accident would be incurred by extending the operating cycle due to

an increased surveillance interval.

2. The possibility of a new or different kind of accident from

any previously analyzed has not been created.

The failure noted from the past test data appears random in

nature and would not have defeated the redundancy in design that

exists in the AFW system. The AFW system would have been capable of

performing its intended safety function and therefore a new or

different kind of accident would not have been created.

3. There has been no reduction in the margin of safety.

Past historical data demonstrates that the AFW systems would

perform their safety function for an extended operating cycle should

the surveillance period be extended by several months.

The NRC staff has reviewed the licensee's analysis and, based on

this review, it appears that the three standards of 50.92(c) are

satisfied. Therefore, the NRC staff proposes to determine that the

amendment request involves no significant hazards consideration.

Local Public Document Room location: White Plains Public Library,

100 Martine Avenue, White Plains, New York 10610.

Attorney for licensee: Brent L. Brandenburg, Esq., 4 Irving Place,

New York, New York 10003.

NRC Project Director: Pao Tsin Kuo

Consolidated Edison Company of New York, Docket No. 50-247, Indian

Point Nuclear Generating Unit No. 2, Westchester County, New York

Date of amendment request: June 16, 1994

Description of amendment request: The proposed amendment would

revise License Condition 2.K of the license issued August 24, 1981, to

provide for compliance with the NRC-approved fire protection program as

described in the Updated Final Safety Analysis Report and for making

changes to the NRC-approved fire protection program; would delete fire

protection Technical Specification (TS) Sections 3.13 and 4.14 which

contain limiting conditions for operation and surveillance

requirements, respectively, for the high-pressure water fire protection

system, fire protection spray systems, penetration fire barriers, fire

detection systems, fire hose stations and hydrants, and the cable

spreading room halon system; would delete Section 6.2.2.f which

contains fire brigade staffing requirements; would delete Section 6.4.2

which contains fire brigade training requirements; would add Section

6.5.1.6.1 to add fire protection program responsibilities to the

Station Nuclear Committee; would add Section 6.8.1.e to require written

procedures and administrative policies for the fire protection program;

would delete Section 6.9.2.b which requires a Special Report for

inoperable fire protection and detection equipment; and would make

corresponding changes to the Table of Contents and List of Tables.

Generic Letter (GL) 86-10, dated April 24, 1986, and GL 88-12,

dated August 2, 1988, from the NRC provided guidance to licensees to

request removal of the fire protection TS. The licensee's proposed

amendment is in response to these GLs.

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensee has

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

The Commission has provided guidance concerning the application

of the standards for determining whether a ``Significant Hazards

Consideration'' exists by providing certain examples in 51 FR 7744

(dated March 6, 1986). Example (vii) of those involving no

significant hazards considerations relates to ``a change to conform

a license to changes in the regulations, where the license change

results in very minor changes to facility operations clearly in

keeping with the regulations.''

In this case, NRC Generic Letters 86-10 and 88-12, although not

regulations, provide pertinent guidance relative to the above

described proposed changes and implementation of the NRC fire

protection regulations of 10 CFR 50.48(a). Specifically, the generic

letters allow licensees to delete fire protection related technical

specifications, provided that administrative requirements are added

to technical specifications and a license condition is provided that

requires the implementation and maintenance in effect of the

approved fire protection program. Further, the generic letters

provide for inclusion of the fire protection program into the UFSAR

[Updated Final Safety Analysis Report] and permits future changes to

the fire protection program without prior NRC approval, all as

provided by the license condition and in accordance with the

provisions of 10 CFR 50.59. Therefore, since the actions required by

the generic letters have been taken and conform the license to the

current interpretation of NRC fire protection regulations as

described in Generic Letters 86-10 and 88-12, with no changes to

facility operations, these proposed changes are in accordance with

Example (vii) above.

In accordance with the requirements of 10 CFR 50.92, the

proposed changes to the Technical Specifications are deemed not to

involve any ``Significant Hazards Considerations'' because operation

of Indian Point Unit No. 2 in accordance with these changes would

not:

(1) Involve a significant increase in the probability or

consequences of an accident previously evaluated.

The fire protection program requirements are not affected in

that the function, operation or surveillance requirements for any

fire protection system or component are not being altered. The

proposed changes simply relocate these requirements from the

Technical Specifications to the UFSAR, are administrative in nature,

and do not affect any other current plant equipment or practices.

Therefore, the conclusions of current accident analyses are not

affected. Further, as permitted by the proposed License Condition

2.K, changes in the NRC-approved fire protection program will

require an evaluation per the criteria of 10 CFR 50.59 to determine

that the proposed change will not involve an unreviewed safety

question. Therefore, future changes to the fire protection program

will be evaluated in accordance with appropriate criteria.

(2) Create the possibility for a new or different kind of

accident from any previously evaluated.

The proposed changes introduce no new mode of plant operation,

do not involve physical modification to any structure, system or

component, do not affect the function, operation or surveillance

requirements for any equipment necessary for safe operation or

shutdown of the plant or of fire protection equipment which protects

such equipment, and do not involve any changes to setpoints or

operating parameters. The changes are administrative only and all

existing fire protection requirements are maintained. Therefore, the

changes can not result in an unanalyzed accident. Further, as

permitted by the proposed License Condition 2.K, changes in the NRC-

approved fire protection program will require an evaluation per the

criteria of 10 CFR 50.59 to determine that the proposed change will

not involve an unreviewed safety question. Therefore, future changes

to the fire protection program will be evaluated in accordance with

appropriate criteria.

(3) Involve a significant reduction in the margin of safety.

The existing fire protection program operability and

surveillance requirements are retained as they are contained in the

FPPP [Fire Protection Program Plan], and compliance will continue

through proposed License Condition 2.K. Therefore, no margins of

safety established by design or verified by testing to ensure

operability of fire protection systems or components are affected.

Further, as permitted by the proposed License Condition 2.K, changes

in the NRC-approved fire protection program will require an

evaluation per the criteria of 10 CFR 50.59 to determine that the

proposed change will not involve an unreviewed safety question.

Therefore, future changes to the fire protection program will be

evaluated in accordance with appropriate criteria.

Based on the above discussion, since these proposed changes to

the Indian Point Unit No. 2 Technical Specifications satisfy the

criteria specified in 10 CFR 50.92, are similar to an example

provided by the Commission of a change which involves ``No

Significant Hazards Considerations'', and are not similar to any

examples that involve a ``Significant Hazards Consideration'', Con

Edison has determined that this amendment application does not

involve any ``Significant Hazards Considerations.''

The proposed Technical Specification changes have been reviewed

by the Station Nuclear Safety Committee and the Con Edison Nuclear

Facilities Safety Committee. Both committees concur that these

proposed changes do not represent any ``Significant Hazards

Considerations.''

The NRC staff has reviewed the licensee's analysis and, based on

this review, it appears that the three standards of 50.92(c) are

satisfied. Therefore, the NRC staff proposes to determine that the

amendment request involves no significant hazards consideration.

Local Public Document Room location: White Plains Public Library,

100 Martine Avenue, White Plains, New York 10610.

Attorney for licensee: Brent L. Brandenburg, Esq., 4 Irving Place,

New York, New York 10003.

NRC Project Director: Michael L. Boyle

Consolidated Edison Company of New York, Docket No. 50-247, Indian

Point Nuclear Generating Unit No. 2, Westchester County, New York

Date of amendment request: July 8, 1994

Description of amendment request: The proposed amendment would

revise Technical Specification Section 3.7, Auxiliary Electrical

Systems to clarify offsite power availability requirements and to

revise emergency diesel generator fuel oil availability requirements.

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensee has

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

Consistent with the requirements of 10 CFR 50.92, the enclosed

application involves no significant hazards based on the following

information:

1) Does the proposed license amendment involve a significant

increase in the probability or consequences of an accident

previously evaluated?

Response:

Neither the probability nor the consequence of an accident

previously analyzed is increased due to the proposed changes. There

are no changes on the existing offsite power supply configuration or

on the existing diesel fuel oil supply system or inventory

requirements. This proposed amendment will allow for three diesel

operation when a fuel oil storage tank or transfer pump is

unavailable. In the event of an accident at this time, the three

diesel operation would allow for more than minimum safeguards to be

available, with maximum safeguards available for the first part of

the event.

2) Does the proposed license amendment create the possibility of

a new or different kind of accident from any previously evaluated?

Response:

The existing 138 kV and 13.8 kV offsite power reliability is

maintained with this change. There is no impact on availability of

the alternate AC system, the three gas turbines, with this change.

This change is consistent with the original licensing basis that the

AEC accepted for the diesel fuel oil supply system.

3) Does the proposed amendment involve a significant reduction

in the margin of safety?

Response:

The proposed amendment does not involve a significant reduction

in the margin of safety. The proposed amendment maintains the

reliability of the preferred 138 kV and 13.8 kV offsite power and is

consistent with the original licensing basis for diesel fuel oil

inventory.

The NRC staff has reviewed the licensee's analysis and, based on

this review, it appears that the three standards of 50.92(c) are

satisfied. Therefore, the NRC staff proposes to determine that the

amendment request involves no significant hazards consideration.

Local Public Document Room location: White Plains Public Library,

100 Martine Avenue, White Plains, New York 10610.

Attorney for licensee: Brent L. Brandenburg, Esq., 4 Irving Place,

New York, New York 10003.

NRC Project Director: Robert A. Capra

Duquesne Light Company, et al., Docket No. 50-334, Beaver Valley

Power Station, Unit No. 1, Shippingport, Pennsylvania

Date of amendment request: July 29, 1994

Description of amendment request: The proposed amendment would

revise Technical Specifications (TSs) 3/4.4.5 and 3/4.4.6.2 and

associated bases to allow the implementation of interim steam generator

tube plugging criteria for the tube support elevations during cycle 11.

The allowed primary-to-secondary operational leakage from any one steam

generator is proposed to be reduced from 500 gallons per day (gpd) to

150 gpd. The total allowed primary-to-secondary operational leakage

from all steam generators would be reduced from one gallon per minute

(1440 gpd) to 450 gpd.

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensee has

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

1. Does the change involve a significant increase in the

probability or consequences of an accident previously evaluated?

Testing of model boiler specimens for free span tubing (no tube

support plate [TSP] restraint) at room temperature conditions

show[s] burst pressures in excess of 5000 psi for indications of

outer diameter stress corrosion cracking with voltage measurement as

high as 19 volts. Burst testing performed on intersections pulled

from BVPS [Beaver Valley Power Station] with up to a 2.7 volt

indication shows measured burst pressure in excess of 6600 psi at

room temperature. Burst testing performed on pulled tubes from other

plants with up to 7.5 volt indications show[s] burst pressures in

excess of 6300 psi at room temperatures. Correcting for the effects

of temperature on material properties and minimum strength levels

(as the burst testing was done at room temperature), tube burst

capability significantly exceeds the safety factor requirements of

RG [Regulatory Guide] 1.121. As stated earlier, tube burst criteria

are inherently satisfied during normal operating conditions due to

the proximity of the TSP. Test data indicates that tube burst cannot

occur within the TSP, even for tubes which have 100 percent through

wall electric discharge machining (EDM) notches, 0.75 inch long,

provided that the TSP is adjacent to the notched area. Since tube to

TSP proximity precludes tube burst during normal operating

conditions, use of the criteria must retain tube integrity

characteristics which maintain a margin of safety of 1.43 times the

bounding faulted condition steam line break (SLB) pressure

differential. As previously stated, the RG 1.121 criterion requiring

maintenance of a safety factor of 1.43 times the SLB pressure

differential on tube burst is satisfied by 7/8 inch diameter tubing

with bobbin coil indications with signal amplitudes less than 8.82

volts regardless of the indicated depth measurement. The plugging

criteria (resulting in a projected end-of-cycle [EOC] voltage)

compares favorably with the 8.82 volt structural limit considering

the extremely slow apparent voltage growth rate of indications at

BVPS. Using the established methodology of RG 1.121, the structural

limit is reduced by allowances for uncertainty and growth to develop

a beginning-of-cycle (BOC) repair limit which should preclude

indications at EOC conditions which exceed the structural limit. The

non-destructive examination (NDE) uncertainty component is 20.5

percent and is based on the EPRI [Electric Power Research Institute]

Alternate Repair Criteria (ARC). A bounding growth allowance of 40

percent will be applied. This value is conservative for BVPS Unit 1.

The BOC maximum allowable repair limit should not permit the

existence of EOC indications (when the 40 percent growth and 20.5

percent uncertainty allowances are applied) which exceed the 8.82

volt structural limit. By adding NDE uncertainty allowances and an

allowance for crack growth to the repair limit, the structural limit

can be validated. Therefore, the maximum allowable BOC repair limit

(RL) based on the structural limit of 8.82 volts can be represented

by the expression:

RL + (0.205 X RL) + (0.40 x RL) = 8.82 volts, or the maximum

allowable BOC repair limit can be expressed as:

RL = 8.82 volt structural limit/1.605 = 5.5 volts.

It is reasonable that this repair limit (5.5 volts) could be

applied for IPC [interim plugging criterion] implementation to

repair bobbin indications greater than 1.0 or 2.0 volts independent

of RPC [rotating pancake coil] confirmation of the indication. The

analyses were performed based on a 1.0 or 2.0 volt repair limit.

Duquesne Light Company has chosen to use a steam generator tube

repair limit of 1.0 volt. Conservatively, an upper limit of 3.6

volts will be used to assess tube integrity for those bobbin

indications which are above 1.0 volt but do not have confirming RPC

calls. This 3.6 volt upper limit for non-confirmed RPC calls is

consistent with other recently approved IPC programs for the two

other plants with 7/8 inch tubing that currently implement IPCs.

Since the upper bound for repair of non-confirmed RPC is limited to

a value far less than the limit associated with a full alternate

criteria, the establishment of the repair limits are [is] judged to

be independent of the pulled tube data base used.

The conservatism of the growth allowance used to develop the

repair limit is shown by the most recent BVPS eddy current data. The

average voltage growth for all indications was 16 percent while the

average voltage growth for indications greater than 0.75 volts at

BOC was 6 percent. The largest overall voltage growth in a

particular steam generator was found in the ``A'' steam generator,

which had an overall average growth of 25 percent. Only two tubes

had an absolute voltage growth which exceeded 1.0 volt for Cycle 9.

The maximum absolute voltage growth in the 1993 inspection was

recorded to be 1.18 volts. Each of the last three inspections, which

included 100 percent of all hot leg tubes, showed decreasing voltage

growth trends in each successive inspection for all categories;

overall voltage growth, growth of BOC indications less than 0.75

volts, and growth of indications greater than 0.75 volts. The

decreasing voltage growth rate trend data indicates that DLC has

good control of the ODSCC [outer diameter stress corrosion cracking]

occurring in the BVPS Unit 1 steam generators and also implies that

atypical voltage growth of a few indications is unlikely.

Relative to the expected leakage during accident condition

loadings, it has been previously established that a postulated main

SLB [steam line break] outside of containment but upstream of the

main steam isolation valve (MSIV) represents the most limiting

radiological condition relative to the IPC. In support of

implementation of the interim plugging criteria, it will be

determined whether the distribution of cracking indications at the

TSP intersections at the end of Cycle 11 are [is] projected to be

such that primary-to-secondary leakage would result in site boundary

doses within a small fraction of the 10 CFR 100 guidelines. A

separate calculation has determined this allowable SLB leakage limit

to be 6.6 gpm in the faulted loop. This limit was calculated using

the Technical Specification RCS [reactor coolant system] Iodine-131

activity level of 1.0 micro Curies per gram dose equivalent Iodine-

131 and the recommended Iodine-131 transient spiking values

consistent with NUREG-0800. The projected SLB leakage rate

calculation methodology prescribed in Section 3.3 of draft NUREG-

1477 will be used to calculate EOC leakage. The log-logistic

probability of leakage correlation will be used to establish the SLB

leak rate used for comparison with the 6.6 gpm faulted loop

allowable limit. Due to the relatively low voltage levels of

indications at BVPS and low voltage growth rates, it is expected

that the actual calculated leakage values will be far less than this

limit. Additionally, the current Iodine-131 levels as of May 1994 at

BVPS are about 1000 times less than the Technical Specification

limit of 1.0.

Application of the criteria requires the projection of

postulated SLB leakage, based on the projected EOC voltage

distribution for the upcoming cycle. Projected EOC voltage

distribution is developed using the most recent EOC eddy current

results and a voltage measurement uncertainty. Data indicate that a

threshold voltage of 2.8 volts would result in through wall cracks

long enough to leak at steam line break conditions. Draft NUREG-1477

requires that all indications to which the IPC are applied must be

included in the leakage projection. Tube pull results from another

plant with 7/8 inch tubing with a substantial voltage growth data

base have shown that tube wall degradation of greater than 40

percent through wall was readily detectable either by the bobbin or

RPC probe. The tube with maximum through wall penetration of 56

percent (42 percent average) had a voltage of 2.02 volts. This

indication also was the largest recorded bobbin voltage from the EOC

eddy current data. Based on the BVPS pulled tube and industry pulled

tube data supporting a lower threshold for SLB leakage of 2.8 volts,

inclusion of all IPC intersections in the leakage model is quite

conservative. The ODSCC occurring at BVPS has historically resulted

in relatively low voltage levels and has exhibited decreasing

voltage growth trends over the last three inspections. BVPS has not

identified ODSCC as a contributor to operational leakage. The

current leakage levels at BVPS are negligible (less than 1 gpd). In

order to satisfy the requirements of draft NUREG-1477, EOC 10 eddy

current data will be used to calculate the projected SLB leakage

according to draft NUREG-1477 methodology. Leakage calculated using

the recommended EPRI leakage correlation will also be provided.

Duquesne Light Company is requesting that the NRC review and approve

the EPRI SLB leakage calculation methodology. Sufficient

justification is included to establish acceptability of the EPRI

leakage correlation based on criteria provided by the NRC in the

February 8, 1994, Industry/NRC working meeting on the voltage based

criteria.

In order to assess the sensitivity of application of the voltage

based criteria upon SLB leakage, the EOC 9 eddy current results were

used to calculate postulated EOC 10 leakage using both the NUREG-

1477 methodology and EPRI correlation assuming that a 1.0 or 2.0

volt plugging limit were implemented at the BOC 10.

Results indicate SLB leakage of 0.46 gpm and 0.044 gpm using the

NUREG and EPRI methodologies with an assumed probability of

detection (POD) of 0.6 for a 2.0 volt repair limit. Since Duquesne

Light Company has chosen to limit the voltage based plugging limit

at 1.0 volt, EOC 11 SLB leakage is analyzed to be approximately 5

percent lower than the calculated SLB leakage with a 2.0 volt repair

limit.

Therefore, implementation of the interim plugging criteria does

not adversely affect steam generator tube integrity and

implementation will be shown to result in acceptable dose

consequences, therefore, the proposed amendment does not result in

any increase in the probability or consequences of an accident

previously evaluated.

2. Does the change create the possibility of a new or different

kind of accident from any accident previously evaluated?

Implementation of the proposed steam generator tube interim TSP

plugging criteria does not introduce any significant changes to the

plant design basis. Use of the criteria does not provide a mechanism

which could result in an accident outside of the region of the TSP

elevations; no ODSCC that has been identified at the TSP has been

detected outside the thickness of the TSPs. Neither a single or

multiple tube rupture event would be expected in a steam generator

in which the plugging criteria has been applied (during all plant

conditions).

Specifically, Duquesne Light Company will implement a maximum

leakage rate limit of 150 gpd per steam generator to help preclude

the potential for excessive leakage during all plant conditions. The

technical specification limits on primary-to-secondary leakage at

operating conditions are to be a maximum of 450 gpd for all steam

generators, or, a maximum of 150 gpd for any one steam generator.

The RG 1.121 criterion for establishing operational leakage rate

limits that require plant shutdown are based upon leak-before-break

considerations to detect a free span crack before potential tube

rupture during faulted plant conditions. The 150 gpd limit should

provide for leakage detection and plant shutdown in the event of the

occurrence of an unexpected single crack resulting in leakage that

is associated with the longest permissible crack length. RG 1.121

acceptance criteria for establishing operating leakage limits are

based on leak-before-break considerations such that plant shutdown

is initiated if the leakage associated with the longest permissible

crack is exceeded.

The single through wall crack lengths that result in tube burst

at 1.43 times the steam line break pressure differential and SLB

pressure differential alone are approximately 0.57 inch and 0.84

inch, respectively. A leak rate of 150 gpd will provide for

detection of 0.41 inch long cracks at nominal leak rates and 0.62

inch long cracks at the lower 95 percent confidence level leak

rates. Since tube burst is precluded during normal operation due to

the proximity of the TSP to the tube and the potential exists for

the crevice to become uncovered during SLB conditions, the leakage

from the maximum permissible crack must preclude tube burst at SLB

conditions. Thus, the 150 gpd limit provides for plant shutdown

prior to reaching critical crack lengths for SLB conditions using

the lower 95 percent leakage data. Additionally, this leak-before-

break evaluation assumes that the entire crevice area is uncovered

during blowdown. Partial uncovery will provide benefit to the burst

capacity of the intersection. Analyses have shown that only a small

percentage of the TSPs are deflected greater than the TSP thickness

during a postulated SLB.

Steam generator tube integrity continues to be maintained

through inservice inspection and primary-to-secondary leakage

monitoring, therefore, the possibility of a new or different kind of

accident from any accident previously developed is not created.

3. Does the change involve a significant reduction in a margin

of safety?

The use of the voltage based bobbin probe interim TSP elevation

plugging criteria is demonstrated to maintain steam generator tube

integrity commensurate with the requirements of RG 1.121. RG 1.121

describes a method acceptable to the NRC staff for meeting GDCs 14,

15, 31, and 32 by reducing the probability or the consequences of

steam generator tube rupture. This is accomplished by determining

the limiting conditions of degradation of steam generator tubing, as

established by inservice inspection, for which tubes with

unacceptable cracking should be removed from service. Upon

implementation of the criteria, even under the worst case

conditions, the occurrence of ODSCC at the TSP elevations is not

expected to lead to a steam generator tube rupture event during

normal or faulted plant conditions. The EOC distribution of crack

indications at the TSP elevations will be confirmed to result in

acceptable primary-to-secondary leakage during all plant conditions

and that radiological consequences are not adversely impacted.

In addressing the combined effects of loss of coolant accident

(LOCA) and safe shutdown earthquake (SSE) on the steam generator

component (as required by GDC 2), it has been determined that tube

collapse may occur in the steam generators at some plants. This is

the case as the TSP may become deformed as a result oflateral loads

at the wedge supports at the periphery of the plate due to the

combined effects of the LOCA rarefaction wave and SSE loadings.

Then, the resulting pressure differential on the deformed tubes may

cause some of the tubes to collapse.

There are two issues associated with steam generator tube

collapse. First, the collapse of steam generator tubing reduces the

RCS flow area through the tubes. The reduction in flow area

increases the resistance to flow of steam from the core during a

LOCA which, in turn, may potentially increase peak clad temperature

(PCT). Second, there is a potential that partial through wall cracks

in tubes could progress to through wall cracks during tube

deformation or collapse.

Consequently, since the leak-before-break methodology is

applicable to the BVPS reactor coolant loop piping, the probability

of breaks in the primary loop piping is sufficiently low that they

need not be considered in the structural design of the plant. The

limiting LOCA event becomes either the accumulator line break or the

pressurizer surge line break. LOCA loads for the primary pipe breaks

were used to bound the conditions at BVPS for smaller breaks. The

results of the analysis using the larger break inputs show that the

LOCA loads were found to be of insufficient magnitude to result in

steam generator tube collapse or significant deformation. The LOCA

and SSE tube collapse evaluation performed for another plant with

Series 51 steam generators using bounding input conditions (large

break loadings) is considered applicable to BVPS.

Addressing RG 1.83 considerations, implementation of the bobbin

probe voltage based interim tube plugging criteria is supplemented

by: enhanced eddy current inspection guidelines to provide

consistency in voltage normalization, a 100 percent eddy current

inspection sample size at the TSP elevations, and RPC inspection

requirements for the larger indications left inservice to

characterize the principal degradation as ODSCC.

As noted previously, implementation of the TSP elevation

plugging criteria will decrease the number of tubes which must be

repaired. The installation of steam generator tube plugs reduces the

RCS flow margin. Thus, the implementation of the alternate plugging

criteria will maintain the margin of flow that would otherwise be

reduced in the event of increased tube plugging.

Based on the above, it is concluded that the proposed license

amendment request does not result in a significant reduction in

margin with respect to plant safety as defined in the Final Safety

Analysis Report or any Bases of the Technical Specifications.

The NRC staff has reviewed the licensee's analysis and, based on

this review, it appears that the three standards of 10 CFR 50.92(c) are

satisfied. Therefore, the NRC staff proposes to determine that the

amendment request involves no significant hazards consideration.

Local Public Document Room location: B. F. Jones Memorial Library,

663 Franklin Avenue, Aliquippa, Pennsylvania 15001.

Attorney for licensee: Gerald Charnoff, Esquire, Jay E. Silberg,

Esquire, Shaw, Pittman, Potts & Trowbridge, 2300 N Street, NW.,

Washington, DC 20037.

NRC Project Director: Walter R. Butler, Director

Entergy Operations, Inc., Docket Nos. 50-313, Arkansas Nuclear One,

Unit 1, Pope County, Arkansas

Date of amendment request: June 22, 1994

Description of amendment request: The proposed amendment revises

technical specifications (TSs) related to the emergency feedwater

system (EFW). The proposed changes extend the allowable outage time

when one EFW train is inoperable from 36 hours to 72 hours and adapt

other EFW sections from the ``Restructured Standard Technical

Specifications for B&W Plants'' to the Arkansas Nuclear One, Unit 1

(ANO-1) format.

Basis for proposed no significant hazards consideration

determination: As required by 10 CFR 50.91(a), the licensee has

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

Criterion 1 - Does Not Involve a Significant Increase in the

Probability or Consequences of an Accident Previously Evaluated.

The Emergency Feedwater (EFW) system mitigates the consequences

of any event with a loss of normal feedwater. This system is not the

initiator of any previously analyzed accident, and therefore,

changes to the specifications applicable to the EFW system present

no significant increase in the probability of any previously

evaluated accident.

The changes that revise the required Actions and Allowable

Outage Times associated with the EFW system have been evaluated for

their effect on the Core Damage Frequency (CDF) previously

calculated in the ANO-1 Probabilistic Risk Assessment (PRA). The new

ANO-1 CDF values, incorporating the proposed AOT extension, are

4.73E-05 (for the turbine-driven EFW pump) and 4.70E-05 (for the

motor-driven pump). These values do not exceed the NRC Safety Goal

of 1.0E-04 per reactor year, as stated in the Federal Register

50FR32138. The delta CDF associated with these changes (6.16E-07 for

the turbine-driven EFW pump and 3.04E-07 for the motor-driven EFW

pump) have been evaluated with respect to criteria contained in

SECY-91-270, dated August 27, 1991, and NUMARC 91-04, dated January

1992, and fall within the category of events of low risk

significance requiring no compensatory measures. This evaluation has

shown the risk associated with the proposed changes to pose no undue

risk to public health and safety, to be categorized as having low

risk significance, and involve no significant increase in the

consequences of an accident previously evaluated.

The changes revising the Limiting Conditions for Operation

result in more restrictive controls on the operability of the motor-

driven EFW pump. The previous specification required operability of

both EFW pumps when the reactor was heated above 280 deg.F. The

proposed change requires the operability of the motor-driven EFW

pump whenever the unit is above the cold shutdown condition and any

steam generator is relied upon for heat removal. With this change,

the motor-driven EFW pump is now required to be operable in a

condition not previously specified, constituting an additional

requirement not previously specified. This change does not involve a

significant increase in the consequences of an accident previously

evaluated.

The changes revising the Limiting Conditions for Operation also

incorporate an Allowable Outage Time for the turbine-driven EFW pump

steam supply valves which was not previously specified. The 7 day

AOT is reasonable based on:

1. The redundant steam supply (from the opposite steam

generator) to the turbine-driven EFW pump is operable,

2. The motor-driven EFW pump is operable, and

3. The probability of an event occurring that would require the

inoperable steam supply valve to actuate is relatively low.

The changes to the surveillance specifications clarify the

proper conditions required for the operability test of the turbine-

driven EFW pump, and revise the requirement for the verification of

proper EFW flow path valve alignment. The change clarifying the test

conditions is required to ensure a sufficient steam supply to the

turbine-driven EFW pump to perform the test. During plant startup,

from an RCS temperature of 280 deg.F to an RCS temperature of

approximately 525 deg.F (corresponding to a steam generator pressure

of approximately 830 psig) the turbine-driven EFW pump is classified

as available until operability is proven by successful completion of

the surveillance requirement. The proposed changes state that the

EFW pumps and their associated flow paths shall be operable when the

RCS is above the cold shutdown condition with any steam generator

relied upon for heat removal (motor-driven EFW pump) and when RCS

temperature is greater than or equal to 280 deg.F (turbine-driven

EFW pump). This specification requires that the flow paths be

properly aligned to maintain operability and is as restrictive as

the current TS 4.8.1.c. The revised specification incorporates a new

requirement to verify operator flexibility in determining the method

of verification. Some methods that could be considered as fulfilling

this requirement would include valve alignment checks, or a flow

test verifying a level decrease in the `Q' condensate storage tank

with a corresponding level increase in both steam generators. These

changes result in no significant increase in the consequences of an

accident previously evaluated.

The other proposed changes included in this submittal, including

the Bases changes, are considered to be administrative in nature and

have no effect on the consequences of an accident previously

evaluated. Relocation of the Emergency Feedwater Initiation and

Control (EFIC) requirements from Section 3.4 to Section 3.5 places

the requirements for this instrumentation system with the

requirements for other instrumentation systems, resulting in greater

consistency throughout the ANO-1 TS. Information in the Bases

associated with the EFIC system has been corrected to reflect the

actual plant condition and resolve a conflict with the ANO-1 Safety

Analysis Report. The Bases changes add clarifying information to aid

the operator in determining the applicability of the various EFW

specifications.

Therefore, this change does not involve a significant increase

in the probability or consequences of any accident previously

evaluated.

Criterion 2 - Does Not Create the Possibility of a New or

Different Kind of Accident from any Previously Evaluated.

The proposed changes introduce no new mode of plant operation.

The EFW system is not an event initiator. It functions to mitigate

the consequences of any event with a loss of normal feedwater.

Therefore, this change does not create the possibility of a new

or different kind of accident from any previously evaluated.

Criterion 3 - Does Not Involve a Significant Reduction in the

Margin of Safety.

The changes proposed to the Limiting Conditions for Operation

associated with the EFW system are more conservative than the

current specification, thus resulting in an increase in the margin

of safety. The proposed changes to the actions required when both of

the EFW trains are inoperable and the auxiliary feedwater pump is

unavailable no longer require an immediate plant runback, that is

currently required, which could introduce a plant transient, thus

resulting in an increase in the margin of safety.

The changes revising the Limiting Conditions for Operations also

incorporate and Allowable Outage Time for the turbine-driven EFW

pump steam supply valves which was not previously specified. The 7

day AOT is reasonable based on: