Biweekly Notice

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 August 22, 1994 through September 1, 1994.

The last biweekly notice was published on August 31, 1994 (59 FR

45015).

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 October 14, 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.

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: August 2, 1994

Description of amendments request: The proposed amendment would

revise Technical Specifications (TSs) 3.9.1 and 3.1.2.7 and the Bases

to Specification 3.1.2.7. Specifically, TS 3.9.1, ``Refueling

Operations, Boron Concentration,'' would be revised to require action

to restore boron concentration to within its limits in place of the

current requirement to initiate and continue boration at a rate greater

than or equal to 40 gpm of 2300 ppm boric acid solution or its

equivalent until the boron concentration is within its limit. TS

3.1.2.7, ``Borated Water Sources - Shutdown,'' gives the operability

requirement for borated water sources including the Refueling Water

Tank (RWT), in Modes 5 and 6. The minimum boron concentration is given

as 2300 ppm. While this minimum value is correct for Mode 5, a larger

boron concentration may be necessary in Mode 6. The RWT is the

preferred borated water source for restoring the required boron

concentration as required by TS 3.9.1. Therefore, the RWT boron

concentration in Mode 6 should be at least be that required by TS

3.9.1. The proposed change to TS 3.1.2.7 would clarify the boron

concentration requirements. In Mode 5, 2300 ppm will continue to be

required. In Mode 6, the boron concentration limit for the RWT will be

the boron concentration limits given in TS 3.9.1.

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.

During refueling operations, the reactivity condition of the

core is maintained consistent with the initial conditions assumed

for the boron dilution event in the accident analysis (Updated Final

Safety Analysis Report Section 14.3) and is sufficient to ensure the

core remains subcritical during core alterations. Technical

Specification 3.9.1 requires that the boron concentration be

maintained to ensure a keff [is less than or equal to] 0.95.

Should the boron concentration drop below the Technical

Specifications limit, the Action requires boration at a specified

flow rate and boron concentration until the boron concentration is

restored to within its limit. Refueling boron concentrations higher

than the concentration specified by the Action in [Technical]

Specification 3.9.1 are allowed by the Technical Specifications and

clarification of the Action for that circumstance is needed. The

proposed change eliminates the specified flow rate and boron

concentration in the Action and substitutes a directive to

immediately initiate action to restore the boron concentration to

within its limits. The accident analysis does not assume a specific

boration rate, but only assumes that the operator acts to terminate

the dilution.

Therefore, the consequences of the event are unchanged. In

addition, the proposed change revises the boron concentration limit

on the Refueling Water Tank in Mode 6 to make the boron

concentration limit on the tank the same as the boron concentration

limit on the reactor coolant system. This will ensure that the RWT

will contain water of a sufficient boron concentration to respond to

a boron dilution event.

The proposed change does not change the boron concentration or

shutdown margin required by [Technical] Specification 3.9.1 and

continues to meet the initial conditions of the boron dilution

event. Therefore, the probability of a boron dilution event is not

increased. Furthermore, the revised action ensures that the

appropriate actions for a boron dilution event will be taken and

that a borated water source of sufficient concentration is available

to respond to that event. Therefore, the consequences of a boron

dilution event are not increased.

Therefore, the proposed change does not involve a significant

increase in 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.

The proposed change does not represent a significant change in

the configuration or operation of the plant. The proposed actions

will results in the same operator actions as the current Technical

Specifications. The minimum boron concentration of the Refueling

Water Tank in Mode 6 may be increased above the current value, but

the concentrations will be within the analyzed maximum concentration

for that tank,

Therefore, the proposed change does not create the possibility

of a new or different type of accident from any accident previously

evaluated.

3. Would not involve a significant reduction in a margin of

safety.

The margin of safety provided by [Technical] Specification 3.9.1

is to ensure that the core remains subcritical during a boron

dilution event and during core alterations. The proposed change does

not alter the required shutdown margin or significantly change the

actions to be taken if that shutdown margin is lost. The proposed

change ensures that all assumed borated water sources will have

sufficient boron concentration to respond to boron dilution event.

Therefore, the proposed change does not involve a significant

reducation 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: 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 J. Case

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: August 2, 1994

Description of amendments request: The proposed change would

revise Technical Specifications (TSs) regarding surveillances

associated with the Emergency Diesel Generators (EDGs). Specifically,

TS 4.8.1.1.2.d.3.c would be revised to add high crankcase pressure to

the EDG trips which are verified to be automatically bypassed on a

Safety Injection Actuation Signal (SIAS). In addition, a footnote would

be added stating that verification of the high crankcase pressure trip

bypass will not be required on a particular EDG until the modification

has been completed for that EDG.

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 Calvert Cliffs Emergency Diesel Generators (EDGs) are used

to provide electrical power for the operation of Engineered Safety

Features (ESF) and safe shutdown equipment for events involving a

loss of offsite power. The EDGs are also called upon to

automatically start if an accident condition (SIAS) is present. In

the event of an automatic start from a SIAS, the EDGs do not assume

any load until the preferred, offsite power source is actually lost.

On an undervoltage condition on a vital bus, the corresponding EDGs

automatically start and load.

Emergency diesel generator trips are provided to initiate engine

shutdown during abnormal diesel-run conditions, thereby protecting

the EDGs from any resulting damage. Under emergency conditions, EDG

reliability is a key accident-mitigating factor; therefore, upon

receipt of a SIAS, the EDG control logic blocks two of the normal

shutdown signals so that the only signals remaining are those

required to prevent rapid destruction of the diesel engine. High

crankcase pressure is typically not an indication of impending rapid

diesel engine failure; therefore, this trip will be added to those

shutdown signals bypassed on a SIAS. The proposed Technical

Specification change adds the high crankcase pressure trip as one of

the EDG trips verified to be bypassed by a SIAS. A high crankcase

pressure condition on one EDG will not impact either of the two

unaffected EDGs, or any other equipment required to mitigate

accident consequences, and satisfies the single failure criteria.

The manufacturer concurs with the proposed change to bypass this

trip on a SIAS. In blocking this trip on a SIAS, the ultimate effect

is an increase in the reliability of the effected EDG, and

therefore, no increase in the consequences of a previously evaluated

accident.

Additionally, the EDGs are not initiators to any previously

evaluated accident. Therefore, blocking the high crankcase pressure

trip on a SIAS will not increase the probability of an accident

previously evaluated.

Therefore, the proposed change does not involve a significant

increase to 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.

The function of the EDGs is to provide power to ESF and safe

shutdown equipment for events involving a loss of offsite power. The

proposed change does not represent a significant change in the

configuration or operation of the plant; therefore, the EDGs

continue to function in an accident mitigation role. The EDGs are

not accident precursors, either in the current configuration, or

following the modification to block the high crankcase pressure

trip.

Therefore, the proposed changes do not create the possibility of

a new or different type of accident from any accident previously

evaluated.

3. Would not involve a significant reduction in a margin of

safety.

The margin of safety credited with the EDG function associated

with this change is the reliability of the EDGs following an event

involving a loss of offsite power. By blocking high crankcase

pressure trips on a SIAS, this change increases the likelihood that

an EDG will be able to supply power when it is needed most, during a

SIAS, because the probability of an unnecessary EDG shutdown is

decreased. In effect, the margin of safety associated with this

function, EDG reliability, is increased.

Therefore, the proposed change does not involve a significant

reduction in the 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: 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 J. Case

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: August 4, 1994

Description of amendments request: The proposed amendment would

eliminate Technical Specifications 3/4.3.3.3, 6.9.2.b, and 6.9.2.d and

Bases 3/4.3.3.3 which gives requirements for seismic monitoring

instrumentation. Specifically, the requirements for operation and

testing of the seismic monitoring instrumentation would be relocated to

the Calvert Cliffs Nuclear Power Plant Updated Final Safety Analysis

Report (UFSAR) and plant procedures.

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 has been evaluated against the standards in

10 CFR 50.92 and has been determined to not involve a significant

hazards consideration, in that operation of the facility in

accordance with the proposed amendments:

1. Would not involve a significant increase in the probability

or consequences of an accident previously evaluated.

The seismic monitoring system is used to measure the seismic

response of selected Class 1 structures, provide time-history

records of seismic events, and would indicate if predetermined

seismic acceleration values had been exceeded. The seismic

monitoring system itself has no safety function. The system measures

values which are used after the fact to assess the intensity of an

earthquake.

The proposed change will relocate requirements regarding the

operability and testing of the seismic monitors from the Technical

Specifications to the UFSAR and plant procedures. This will allow

changes to the requirements to be made without Commission approval

as long as the changes meet the criteria of 10 CFR 50.59. Associated

Technical Specification Special Report requirements and Bases will

be deleted. Changes to the seismic monitoring system requirements

which do not meet the criteria of 10 CFR 50.59 must be approved by

the Commission by license amendment.

The seismic monitoring system is not an initiator and does not

act to minimize the consequences of any accident previously

evaluated. Therefore, the proposed change does not involve a

significant increase in 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?

The proposed relocation of seismic monitor requirements from the

Technical Specifications to the UFSAR and plant procedures does not

represent a change in the configuration or operation of the plant.

The seismic monitoring system will continue to be controlled under

10 CFR 50.59. Associated Technical Specification Special Report

requirements and Bases will be deleted. The proposed change will not

add any new hardware and will not introduce any new accident

initiators. Therefore, the proposed change does 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 seismic monitoring system is used to measure the response of

selected Class 1 structures to seismic events. The plant is designed

to withstand the loads imposed by the maximum hypothetical accident

and the design seismic disturbance without loss of functions

required for reactor shutdown and emergency core cooling. As a

consequence, the seismic monitoring system makes no contribution to

the margin of safety, and neither do the associated special reports.

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: 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 J. Case

Duke Power Company, et al., Docket Nos. 50-413 and 50-414, Catawba

Nuclear Station, Units 1 and 2, York County, South Carolina

Date of amendment request: July 18, 1994

Description of amendment request: The purpose of the proposed

amendment is to separate the Technical Specification (TS) into two

separate volumes, one volume explicitly for Unit 1 and one volume

explicitly for Unit 2. At present, each unit has a single volume of TS

which contains the specifications covering both units. In anticipation

of the steam generator (SG) replacement project scheduled to begin in

the fall of 1994, the licensee is requesting that the TS reflect unit

specific data. Since the SG project outlines a schedule for single

units, the present documentation reflecting both units in one volume

will make it difficult to facilitate TS changes to a single unit. The

proposed TS will modify the current situation as follows:1) The pages

will now contain the same information as found before with the

exception of references to different units. The Unit 1 volume will only

contain parameter and setpoint values applicable to Unit 1; the Unit 2

volume will only contain information applicable to Unit 2.2) The limits

established by the TS (the definitions, the limiting conditions for

operation, the surveillance requirements, the Bases, etc.) will be

unchanged by this amendment, with the exception of (3) below. The

effect of the amendment will be that the Unit 1 TS will be found only

in the volume dedicated solely to Unit 1 and likewise for Unit 2. 3) TS

Sections 3.0.5 and 4.0.6 will be deleted and minor editorial changes,

such as the correction of misspellings and the deletion of obsolete

footnotes, will be made. TS 3.0.5 and 4.0.6 define the applicability of

the current joint TS volume to each unit individually. Since each

unit's TS will be located in a separate volume, no statements are

necessary to indicate differences in parameters between units and TS

3.0.5 and 4.0.6 may be deleted.

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 amendments would not involve a significant increase

in the probability or consequences of a previously evaluated

accident. The separation of the existing technical specification

manual into unit-specific volumes is a strictly administrative

process which will not affect the probability or consequence of any

accident.

They will not create the possibility of a new or different kind

of accident from any accident previously evaluated. The changes do

not have any impact upon the design or operation of plant equipment;

therefore, they cannot serve to initiate a new type of accident.

The proposed amendments would not involve a reduction in a

margin of safety. The changes would not impact the design or

operation of any plant systems or components.

Based upon the preceding analysis, Duke Power Company concludes

that the proposed amendments do not involve a significant hazards

consideration as defined by 10 CFR 50.92.

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: York County Library, 138 East Black

Street, Rock Hill, South Carolina 29730

Attorney for licensee: Mr. Albert Carr, Duke Power Company, 422

South Church Street, Charlotte, North Carolina 28242

NRC Project Director: Herbert N. Berkow

Duke Power Company, Docket Nos. 50-369 and 50-370, McGuire Nuclear

Station, Units 1 and 2, Mecklenburg County, North Carolina

Date of amendment request: July 18, 1994

Description of amendment request: The purpose of the proposed

amendment is to separate the Technical Specifications (TS) into two

separate volumes, one volume explicitly for Unit 1 and one volume

explicitly for Unit 2. At present, each unit has a single volume of TS

which contains the specifications covering both units. In anticipation

of the steam generator (SG) replacement project scheduled to begin in

the fall of 1994, the licensee is requesting that the TS reflect unit

specific data. Since the SG project schedules SG replacement for each

unit at different times, the present common TS would make it difficult

to facilitate TS changes to a single unit. The proposed amendment will

modify the current TS as follows:1) The pages will now contain the same

information as found before with the exception of references to

different units. The Unit 1 volume will only contain parameter and

setpoint values applicable to Unit 1; the Unit 2 volume will only

contain information applicable to Unit 2.2) The limits established by

the TS (the definitions, the limiting conditions for operation, the

surveillance requirements, the Bases, etc.) will be unchanged by this

amendment, with the exception of (3) below. The effect of the amendment

will be that the Unit 1 TS will be found only in the volume dedicated

solely to Unit 1 and likewise for Unit 2.3) TS Sections 3.0.5 and 4.0.6

will be deleted and minor editorial changes, such as the correction of

misspellings and the deletion of obsolete footnotes, will be made. TS

3.0.5 and 4.0.6 define the applicability of the current joint TS volume

to each unit individually. Since each unit's TS will be located in a

separate volume, no statements are necessary to indicate differences in

parameters between units and TS 3.0.5 and 4.0.6 may be deleted.

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 amendments would not involve a significant increase

in the probability or consequences of a previously evaluated

accident. The separation of the existing technical specification

manual into unit-specific volumes is a strictly administrative

process which will not affect the probability or consequence of any

accident.

They will not create the possibility of a new or different kind

of accident from any accident previously evaluated. The changes do

not have any impact upon the design or operation of plant equipment;

therefore, they cannot serve to initiate a new type of accident.

The proposed amendments would not involve a reduction in a

margin of safety. The changes would not impact the design or

operation of any plant systems or components.

Based upon the preceding analysis, Duke Power Company concludes

that the proposed amendments do not involve a significant hazards

consideration as defined by 10 CFR 50.92.

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: Atkins Library, University of North

Carolina, Charlotte (UNCC Station), North Carolina 28223

Entergy Operations, Inc., et al., Docket No. 50-416, Grand Gulf

Nuclear Station, Unit 1, Claiborne County, Mississippi

Date of amendment request: June 17, 1994, as supplemented by letter

dated August 17, 1994.

Description of amendment request: The amendment requests the

removal of license conditions for Transamerica Delaval (TDI) Emergency

Diesel Generators (EDGs) associated with NUREG-1216.

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. Involve a significant increase in the probability or the

consequences of an accident previously evaluated:

The proposed amendment would not involve a significant increase

in the probability or consequences of an accident previously

evaluated. Elimination of the required teardowns and inspections has

no effect on the probability of an accident occurring, because the

diesel generators are not accident initiating equipment. Also,

deleting the teardowns and inspections would decrease the

consequences of an accident because the availability of the engines

would increase as a result of the less frequent teardowns.

Additionally, the high average reliability of the TDI engines would

not be negatively affected due to this change. NRC research has

shown there is a period of decreased reliability immediately

following intrusive teardowns, (break in period), followed by a long

period of high reliability.

2. Create the possibility of a new or different kind of accident

from any previously evaluated:

The proposed amendment would not create the possibility of a new

or different kind of accident from any accident previously

evaluated. The proposed amendment will not cause any physical change

to the plant or the design or operation of the diesel units.

3. Involve a significant decrease in the margin of safety.

The proposed amendment would not involve a significant reduction

in a margin of safety. The proposed amendment will increase the

reliability and availability of the EDGs and therefore will not

result in a decrease in a margin of safety at Grand Gulf.

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: Judge George W. Armstrong Library, Post

Office Box 1406, S. Commerce at Washington, Natchez, Mississippi 39120

Attorney for licensee: Nicholas S. Reynolds, Esquire, Winston and

Strawn, 1400 L Street, N.W., 12th Floor, Washington, DC 20005-3502

NRC Project Director: William D. Beckner

Entergy Operations Inc., Docket No. 50-382, Waterford Steam

Electric Station, Unit 3, St. Charles Parish, Louisiana

Date of amendment request: August 9, 1994

Description of amendment request: The proposed amendment would

revise the technical specifications (TSs) by relocating the functions

under review and audit to the Waterford 3 quality assurance program

manual. The proposed change also incorporates the TS line-item-

improvement of Generic Letter 93-07, ``Modification Of The Technical

Specification Administrative Control Requirements For Emergency And

Security Plans,'' dated December 28, 1993. The changes are proposed to

reduce regulatory burden by relocating TS requirements that are

duplicated by other regulatory 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:

The proposed change will have no affect on design bases

accidents nor will the change directly affect any material condition

of the plant that could directly contribute to causing or mitigating

the effects of an accident. Relocating Review and Audit functions

from the TS is consistent with the NRC Final Policy Statement on

Technical Specifications Improvements and will have no negative

impact on plant operation or safety. Therefore, the proposed change

will not involve a significant increase in the probability or

consequences of any accident previously evaluated.

The proposed change will not alter the operation of the plant or

the manner in which the plant is operated. The change will not

involve a design change or introduce any new failure modes.

Therefore, the proposed change will not create the possibility of a

new or different kind of accident from any accident previously

evaluated.

The proposed change is administrative in nature. The Waterford 3

safety margins are defined and maintained by the Technical

Specifications in Sections 2-5 which are unaffected. Therefore, the

proposed change will 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 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: University of New Orleans Library,

Louisiana Collection, Lakefront, New Orleans, Louisiana 70122

Attorney for licensee: N.S. Reynolds, Esq., Winston & Strawn 1400 L

Street N.W., Washington, D.C. 20005-3502

NRC Project Director: William D. Beckner

Georgia Power Company, Oglethorpe Power Corporation, Municipal

Electric Authority of Georgia, City of Dalton, Georgia, Docket Nos.

50-424 and 50-425, Vogtle Electric Generating Plant, Units 1 and 2,

Burke County, Georgia

Date of amendment request: August 16, 1994

Description of amendment request: The proposed changes revise VEGP

Technical Specification 3/4.7.1.1 and its bases regarding the setpoint

tolerance for the Main Steam Safety Valves (MSSVs).

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. The proposed changes do not involve a significant increase in

the probability or consequences of an accident previously evaluated.

The setpoint tolerance change for the MSSVs from plus or minus 1% to

+2%, -3% is intended to accommodate setpoint drift that may occur

with these valves during plant operation. However, this change will

not adversely affect the pressure boundary integrity or safety

function of the valves. The increase in MSSV setpoint tolerance was

also reviewed with respect to the accident analyses presented in the

VEGP Final Safety Analysis Report (FSAR). The evaluation

demonstrated that the acceptance criteria of the accident analyses

continued to be met. Additionally, the radiological consequences

associated with the accident analysis are unaffected by the proposed

changes. Accordingly, since the performance and capability of the

MSSVs will be maintained as a result of the proposed changes with no

increase in radiological consequences, there will be no significant

increase in the probability or consequences of an accident

previously evaluated.

2. The proposed changes do not create the possibility of a new

or different kind of accident from any accident previously

evaluated. The proposed changes do not involve any change to the

configuration or method of operation of any plant equipment, and no

new failure modes have been defined for any plant system or

component. The design basis requirement for the MSSVs will continue

to be met and the structural integrity of the valves will not be

challenged. Also, the setpoint tolerance change will not adversely

affect the capability of the MSSVs to perform their pressure relief

function to ensure the secondary side steam design pressure is not

exceeded. Additionally, the as-left lift setpoints following testing

of the MSSVs will continue to be within plus or minus 1% of their

lift settings, further ensuring their safety function capability.

Therefore, since the function of the MSSVs is unaffected by the

proposed changes, the possibility of a new or different kind of

accident from any accident previously evaluated is not created.

3. The proposed changes do not involve a significant reduction

in a margin of safety. All applicable acceptance criteria associated

with increasing the MSSV setpoint tolerance will continue to be met.

This includes the structural integrity of the valves and the effect

of the setpoint change on the accident analyses presented in the

VEGP FSAR. Therefore, since the MSSVs remain in compliance with the

appropriate codes and standards and all applicable acceptance

criteria continue to be met, there will not be a significant

reduction in a margin of safety.

Based on the preceding analysis, Georgia Power Company has

determined that the proposed changes to the VEGP Technical

Specifications will not significantly increase the probability or

consequences of an accident previously evaluated, create the

possibility of a new or different kind of accident than any

previously evaluated, or involve a significant reduction in a margin

of safety. Therefore, the proposed changes meet the requirements of

10 CFR 50.92(c) and do not involve a significant hazards

consideration.

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

Local Public Document Room: Burke County Public Library, 412 Fourth

Street, Waynesboro, Georgia 30830.

Attorney for licensee: Mr. Arthur H. Domby, Troutman Sanders,

NationsBank Plaza, Suite 5200, 600 Peachtree Street, NE., Atlanta,

Georgia 30308

NRC Project Director: Herbert N. Berkow

GPU Nuclear Corporation, et al., Docket No. 50-219, Oyster Creek

Nuclear Generating Station, Ocean County, New Jersey

Date of amendment request: August 19, 1994

Description of amendment request: The amendment updates and

clarifies the surveillance requirements for control rod exercising and

standby liquid control pump operability testing including the bases to

be consistent with Generic Letter 93-05.

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. Although the surveillance requirements are lessened by these

proposed changes, the changes are consistent with those found

acceptable by the NRC in GL 93-05. The proposed changes have been

determined to be compatible with our plant operating experience.

Based on these considerations, it is concluded that the changes do

not involve a significant increase in the probability or

consequences of an accident previously evaluated.

2. The proposed changes do not involve physical changes to the

plant or changes in plant operating configuration. The changes only

involve frequency of testing required to be performed. The changes

are consistent with those found acceptable by the NRC in GL 93-05.

Thus, it is concluded that the proposed changes do not create the

possibility of a new or different kind of accident from any accident

previously evaluated.

3. Although the surveillance requirements are lessened by these

proposed changes, the changes are consistent with those found

acceptable by the NRC in GL 93-05. The proposed changes have been

determined to be compatible with our plant operating experience.

Based on these considerations, it is concluded that the changes do

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 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: Ocean County Library, Reference

Department, 101 Washington Street, Toms River, NJ 08753

Attorney for licensee: Ernest L. Blake, Jr., Esquire. Shaw,

Pittman, Potts & Trowbridge, 2300 N Street, NW., Washington, DC 20037.

NRC Project Director: John F. Stolz

IES Utilities Inc., Docket No. 50-331, Duane Arnold Energy Center,

Linn County, Iowa

Date of amendment request: August 15, 1994

Description of amendment request: The proposed amendment would

increase the allowable main steam isolation valve (MSIV) leakage and

delete the Technical Specifications requirements applicable to the MSIV

leakage control system.

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:

Description of Amendment Request:

Proposed Change 1

This proposed change increases the allowable leak rate specified

in Technical Specification (TS) 4.7.A.2.c.3 from 11.5 standard cubic

feet per hour (scfh) for any one main steam isolation valve (MSIV)

when tested at 24 psig to 100 scfh for any one MSIV with a total

maximum pathway leakage rate of 200 scfh through all four main steam

lines when tested at 24 psig. If an MSIV exceeds 100 scfh, it will

be restored to less than or equal to 11.5 scfh.

Basis for proposed no significant hazards consideration

determination:

1. The change does not involve a significant increase in the

probability or consequences of an accident previously evaluated. The

proposed amendment does not involve a change to structures,

components, or systems which would affect the probability of an

accident previously evaluated in the DAEC Updated Final Safety

Analysis Report (UFSAR). It results in acceptable radiological

consequences for the design basis loss of coolant accident (LOCA)

which was previously evaluated in the UFSAR.

Plant specific radiological analyses have been performed to

assess the effects of the proposed increase in the allowable MSIV

leak rate in terms of control room, technical support center (TSC),

and offsite doses following a postulated design basis LOCA. These

analyses utilize the hold-up volumes of the main steam piping and

condenser as an alternate method for treating MSIV leakage. The

radiological analyses use standard conservative assumptions for the

release of source terms consistent with Regulatory Guide 1.3,

``Assumptions Used for Evaluating the Potential Radiological

Consequences of a Loss of Coolant Accident for Boiling Water

Reactors,'' Revision 2, dated June 1974.

Dose contributions from the proposed MSIV leakage rate limit of

100 scfh per MSIV (with a maximum pathway leakage rate not to exceed

200 scfh through all four main steam lines) were calculated. The

analysis demonstrated that the dose contributions from the proposed

MSIV leakage rate resulted in an acceptable increase to the LOCA

doses previously evaluated against the regulatory limits for the

offsite, control room, and TSC doses as contained in 10 CFR 100 and

10 CFR 50, Appendix A (General Design Criterion 19). The revised

LOCA doses are the LOCA doses previously evaluated in the UFSAR plus

the MSIV leakage doses calculated assuming use of the alternate

treatment method. Table 1 of Attachment 2 shows the previously

calculated doses and the newly calculated doses.

It is important to note that the resulting doses are dominated

by the organic iodine fractions which occur because of the

conservative source term assumptions used in this analysis. For a

total leakage rate of 200 scfh through all four main steam lines,

more than 90 percent of the offsite, control room, and TSC iodine

doses are due to the organic iodine from the Regulatory Guide 1.3

source term and organic iodine converted from the elemental iodine

deposited in main steam piping systems. If the actual iodine

composition from the fuel release (cesium iodine) is used in the

calculations, essentially all of this organic iodine dose would be

eliminated.

The TSC doses due to MSIV leakage are especially conservative.

It is not expected that there will be any radioactive releases to

the TSC due to MSIV leakage during the initial stages of a LOCA

since it would take considerable time for the MSIV leakage to travel

through the main steam lines and main steam line drain system to the

condenser, into the turbine building, and finally to the atmosphere

and TSC. It was conservatively estimated that the 30-day integrated

dose to personnel in the TSC would increase by only 0.02 rem. The

dose calculations were performed using control room occupancy

factors specified in NUREG-0800, Standard Review Plan (SRP) Section

6.4.

Therefore, we conclude that the proposed change will not

significantly increase the probability or consequences of any

previously analyzed accidents.

2. The proposed change will not create the possibility of a new

or different kind of accident from any previously evaluated. The

BWROG evaluated MSIV leakage performance and concluded that MSIV

leakage rates up to 100 scfh will not inhibit the capability and

isolation performance of the valves to isolate the primary

containment. There is no new modification to the MSIVs which could

impact their operability. The LOCA has been analyzed using the main

steam piping and condenser as a treatment method to process MSIV

leakage at the proposed maximum rate of 200 scfh through all four

main steam lines. Therefore, the proposed change will not create any

new or different kind of accident from any accident previously

analyzed in the UFSAR.

3. Operation of the DAEC in accordance with the proposed change

will not involve a significant reduction in the margin of safety.

The allowable leak rate limit specified for the MSIVs is used to

quantify a maximum amount of bypass leakage assumed in the LOCA

radiological analysis. Results of the analysis are evaluated against

the dose requirements contained in 10 CFR 100 for the offsite doses

and 10 CFR 50, Appendix A (General Design Criterion 19) for the

control room and TSC doses.

The margins of safety are not significantly affected because the

dose levels remain well below the limits of 10 CFR 100 and General

Design Criterion 19. Therefore, the proposed change does not involve

a significant reduction in the margin of safety at the DAEC.

Description of Amendment Request:

Proposed Change 2

This proposed change to delete TS 3.7.E and 4.7.E and Bases

section 3.7.E and 4.7.E involves eliminating the MSIV leakage

control system (LCS) requirements from the TS.

1. The proposed change does not involve a significant increase

in the probability or consequences of an accident previously

evaluated. As currently described in the UFSAR, the LCS is manually

initiated after a design basis LOCA occurs. Since the LCS is

operated only after an accident has occurred, this proposed

amendment has no effect on the probability of an accident. The

proposed change results in acceptable radiological consequences of

the design basis LOCA previously evaluated in the UFSAR.

The DAEC has an inherent MSIV leakage treatment capability. IES

Utilities Inc. proposes to use the main steam line drains and

condenser as an alternative to the LCS. Figure 1.1 of Attachment 2

shows the primary and alternate drain paths. The proposed primary

drain path at DAEC employs an MSL drain downstream of the MSIVs.

There are two motor-operated valves (MOVs) in series in this line

between the MSL and the main condenser. Both valves must be open to

establish the required drain path. Both MOVs will be provided with

essential power to assure that they can be opened following the DBA

LOCA to establish a large enough drain path to support the

radiological analysis.

An alternate drain path will be available to convey MSIV leakage

to the isolated condenser if either MOV fails to open. The alternate

drain path consists of the bypass lines around the MOVs in the

primary drain path. This alternate path contains a ``fail open''

valve and a restricting orifice. Consequently, if either primary MOV

failed to open as required, the second drain path would be available

to convey MSIV leakage to the main condenser. Radiological dose

calculations have been performed for this alternate path as well as

for the primary path. The results were acceptable. IES Utilities

Inc. will update DAEC procedures as necessary to address the

applicable alternate leakage treatment methods.

IES Utilities Inc. contracted with EQE Engineering Consultants

(EQE) to confirm the seismic capability of the DAEC's main steam

piping and condenser to serve as an alternate leakage treatment

system. Seismic verification walkdowns were performed to assure that

the MSLs, the steam drain lines, the condenser, and interconnecting

piping and equipment that were not seismically analyzed fall within

the bounds of the design characteristics of the seismic experience

database as discussed in Section 6.7 of the BWROG report.

The DAEC main steam lines, main steam drain lines, condenser,

and applicable interconnecting piping and equipment, are well

represented by the earthquake experience data demonstrating good

seismic performance, are confirmed to exhibit excellent resistance

to damage from a design basis earthquake and have been shown to have

substantial margin for seismic capability. The outliers that were

identified are discussed in Attachment 7. They have been either

evaluated to demonstrate their acceptability as they currently

exist, or plant modifications will be implemented to resolve the

concerns. By taking the measures discussed in Attachment 7 to ensure

resolution for all of the identified outliers, IES Utilities Inc. is

assured that the damage reported for the database components should

not occur to the DAEC main steam piping and condenser or to the

associated support systems.

Therefore, the proposed method for MSIV leakage treatment is

seismically adequate to withstand the DAEC design basis earthquake

and maintain pressure retaining integrity and serve as an acceptable

alternative to the currently installed LCS. The capability of the

alternate MSIV leakage treatment system to withstand the effects of

the safe shutdown earthquake and continue to perform its intended

function (treatment of MSIV leakage) satisfies the intent of the

seismic requirement of Appendix A to 10 CFR 100.

Plant specific radiological analyses have been performed to

assess the effects of MSIV leakage in terms of control room and

offsite doses following a postulated design basis LOCA. While not

previously considered a requirement for the design of the LCS, dose

calculations were also performed for the TSC. These analyses utilize

the hold-up volumes of the main steam piping and condenser as an

alternate treatment method for the MSIV leakage. The analysis

demonstrates that the proposed change results in an acceptable

increase in the radiological consequences of a LOCA previously

evaluated in the UFSAR. The LOCA previously evaluated in the UFSAR

is still the bounding accident; the proposed change will not involve

a significant increase in the consequences of an accident previously

analyzed.

The LCS lines will be disconnected, capped and welded, ensuring

that the integrity of the primary containment is maintained. IES

Utilities Inc. will incorporate the alternate leakage treatment

system into the inservice inspection (ISI) and inservice testing

(IST) programs, consistent with program requirements.

2. The proposed change does not create the possibility of a new

or different kind of accident from any previously evaluated. The

purpose of the LCS is to reduce the untreated MSIV leakage when

isolation of the primary coolant system and containment are

required. Radiological dose contributions due to MSIV leakage are

bounded by a LOCA. The LOCA has been analyzed using the main steam

piping and condenser as a treatment method to process MSIV leakage

at the proposed maximum rate of 100 scfh per MSIV and 200 scfh total

maximum pathway leakage, and determined to be within the regulatory

requirements. The LCS lines connected to the main steam lines will

be permanently closed to assure the primary containment integrity,

isolation, and leak testing capability are not compromised.

3. The proposed change to delete TS 3.7.E and 4.7.E and Bases

section 3.7.E and 4.7.E does not involve a significant reduction in

the margin of safety. The intended function of the LCS for treatment

of MSIV leakage will be performed by using the more effective

alternate path via the main steam drain lines and condenser. This

treatment method is effective for treatment of MSIV leakage over an

expanded leakage range. Except for the requirement to assure that

certain valves are opened to establish a proper flow path from the

MSIVs to the condenser and that certain valves are closed to

establish the seismic boundary, the proposed method is passive and

does not require any logic controls or interlocks. On the other

hand, the LCS consists of complicated logic controls and sensitive

equipment which must be maintained at significant cost and radiation

exposure. The radiological effects on the margin of safety are

discussed above for Change 1. The safety significance of the LCS in

terms of public risk was addressed in NUREG/CR-4330 which contains

the evaluation for eliminating the LCS and disabling the systems

currently installed at BWRs. The conclusion was that the increased

public risk is less than 1 percent. Therefore, the proposed change

does not involve a significant reduction in the margin of safety at

the DAEC.

The various attachments referred to in the above analysis may be

found in the licensees request for amendment dated August 15, 1994.

This document is available in the NRC's Public Document Room located at

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

the local public document room address below.

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

thisreview, 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: Cedar Rapids Public Library, 500 First

Street, S.E., Cedar Rapids, Iowa 52401

Attorney for licensee: Jack Newman, Esquire, Kathleen H. Shea,

Esquire, Newman and Holtzinger, 1615 L Street, NW., Washington, DC

20036

NRC Project Director: John N. Hannon

Northeast Nuclear Energy Company, et al., Docket No. 50-423,

Millstone Nuclear Power Station, Unit No. 3, New London County,

Connecticut

Date of amendment request: June 2, 1994, as supplemented August 25,

1994

Description of amendment request: The proposed amendment would

change the Technical Specifications (TS) to remove expired one-time

extensions of surveillances, remove an obsolete definition of charging

pump operability, and incorporate 11 line item improvements in

accordance with the guidance provided in Generic Letter (GL) 93-05.

Other editorial changes would be made to renumber some pages and delete

the blank pages from the TS.

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. The NRC staff has reviewed the licensee's analysis

against the standards of 10 CFR 50.92(c). The NRC staff's review is

presented below.

A. The proposed changes do not involve a significant increase in

the probability or consequences of an accident previously evaluated (10

CFR 50.92(c)(1)). The expired one-time extensions were in effect to

September 30, 1993. Since these extensions have expired and the

appropriate surveillances were performed, the proposed changes do not

effect the configuration, operation, or performance of any system, or

component.

The proposals to delete Definition 1.45, ``THE CHARGING PUMP

OPERABILITY,'' and modify the Index to reflect this change are

administrative changes. Definition 1.45 was applicable only for cycle 4

operation. Northeast Nuclear Energy Company (NNECO) has completed the

necessary modifications and no longer rely on a temporary heating

source. Therefore, the elimination of Definition 1.45 does not involve

a significant increase in the probability or consequences of an

accident previously analyzed.

The proposed changes to incorporate the recommendations of GL 93-05

do not affect the configuration, operation or performance of the

subject systems. Increasing the surveillance test intervals as proposed

will reduce the number of surveillance tests and minimize the potential

for inadvertent actuation of an engineered safety feature. The increase

in the surveillance test intervals will enhance the operational

effectiveness of plant personnel, by reducing the amount of time that

the plant staff has available to perform other tasks, such as

additional preventive maintenance. Additionally, increasing the

surveillance test interval will reduce unnecessary wear to equipment.

NNECO's proposals to delete pages that were intentionally left blank,

to renumber remaining pages and renumber Sections, and modify the Index

to reflect these changes are purely administrative and editorial

changes. Proposals to correct typographical errors on TS pages are also

administrative changes. These changes would not affect the

configuration, operation, or performance of any system, structure, or

component.

The proposed changes do not affect the manner by which the facility

is operated and do not change any facility design feature or equipment.

The proposed changes involve administrative or programmatic

requirements or merely involve editorial changes, corrections, or

clarifications. Since there is no change to the facility or operating

procedures, there is no affect upon the probability or consequences of

any accident previously analyzed.

B. The changes do not create the possibility of a new or different

kind of accident from any accident previously evaluated (10 CFR

50.92(c)(2)) because they do not affect the manner by which the

facility is operated and do not change any facility design feature or

equipment which affects the operational characteristics of the

facility. The proposed changes involve administrative or programmatic

requirements or merely involve editorial changes, corrections, or

clarifications.

C. The changes do not involve a significant reduction in a margin

of safety (10 CFR 50.92(c)(3)) because the proposed changes do not

affect the manner by which the facility is operated or involve

equipment or features which affect the operational characteristics of

the facility.

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: Learning Resource Center, Three Rivers

Community-Technical College, Thames Valley Campus, 574 New London

Turnpike, Norwich, CT 06360.

Attorney for licensee: Ms. L. M. Cuoco, Senior Nuclear Counsel,

Northeast Utilities Service Company, Post Office Box 270, Hartford, CT

06141-0270.

NRC Project Director: John F. Stolz

Northeast Nuclear Energy Company, et al., Docket No. 50-423,

Millstone Nuclear Power Station, Unit No. 3, New London County,

Connecticut

Date of amendment request: July 22, 1994

Description of amendment request: The proposed amendment would

revise the Technical Specifications to incorporate a different setpoint

and transient methodology for determining the maximum allowable power

range neutron flux setpoint. The changes would allow Millstone Unit 3

to operate with a reduced number of main steam-line safety valves at a

reduced power level, as determined by the high neutron flux setpoint.

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 changes do not involve an SHC [significant

hazards consideration] because the changes would not:

1. Involve a significant increase in the probability or

consequences of an accident previously evaluated.

Technical Specification Tables 3.7-1 and 3.7-2 are being revised

to reflect a reduction in the maximum allowable power range neutron

flux high setpoint with inoperable steam generator safety valves.

The new setpoints reflect a change in the methodology for

calculating the setpoints.

Westinghouse has determined that under certain conditions with

typical safety analysis assumptions, the current setpoints in Tables

3.7-1 and 3.7-2 may not provide adequate steam generator

overpressure protection for a Loss of Load/Turbine Trip transient at

reduced power levels. At reduced power levels, a reactor trip may

not be actuated early in the transient. An overtemperature delta T

trip may not be generated since the core thermal margins are

increased at lower power levels. The PORVs [power-operated relief

valves] and pressurizer spray may control RCS [Reactor Coolant

System] pressure such that a high pressurizer pressure trip isn't

generated. The reactor would eventually trip on low steam generator

water level, but this may not occur before steam pressure exceeds

110% of the design value if one or more MSSVs [main steam-line

safety valves] are inoperable.

To address this issue, Westinghouse has developed a new method

for determination of the required power range neutron flux high

setpoint. The new setpoint is based upon the heat removal capability

of the operable MSSVs, rather than the previous method based only on

flow capacity. The new equation is shown in the proposed changes to

the Technical Specification basis. This new method has been

developed by Westinghouse generically and a Millstone Unit No. 3

specific calculation has been performed. The new setpoints are being

incorporated in this proposed Technical Specification change.

The new method includes several conservative assumptions. The

equation is developed assuming that the maximum number of inoperable

MSSVs applies to each loop. For example, for four loop operation,

the maximum allowable power range neutron flux high setpoint of 65%

is based upon four inoperable MSSVs, one per steam generator. Thus,

in the event that only one MSSV is inoperable, the application of

the new setpoint is very conservative. In addition, the setpoint is

based upon the assumption that the largest capacity MSSV is

inoperable. For the case where one of the lower capacity MSSVs is

inoperable, the setpoint will be conservative.

The method of calculating the setpoint provides assurance that

the heat removal capability of the operable MSSVs is sufficient for

reactor power up to the power range neutron flux high setpoint

taking into account instrument and channel uncertainties.

Consequently, steam generator pressure will remain below 110% of

design in the event of the limiting overpressurization transient,

the Loss of Load/Turbine Trip.

Reducing the power range neutron flux high setpoint and

consequently the allowable reduced power level has no impact on the

consequences of any other accident. In addition, since the proposed

changes only involve a reduction in the allowable power range

neutron flux high setpoint, and operation at a lower power level,

they cannot affect the probability of any design basis accident.

2. Create the possibility of a new or different kind of accident

from any previously analyzed.

Since the proposed changes just reduce the existing limit on the

power range neutron flux high setpoint with inoperable MSSVs, the

change cannot create the possibility for a new or different kind of

accident.

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

The reduced setpoint provides additional assurance that the

steam generator pressure will remain below 110% of design for the

limiting overpressurization transient, the Loss of Load/Turbine

Trip. Thus, the proposed changes do not reduce the margin of safety.

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: Learning Resource Center, Three Rivers

Community-Technical College, Thames Valley Campus, 574 New London

Turnpike, Norwich, Connecticut 06360.

Attorney for licensee: Ms. L. M. Cuoco, Senior Nuclear Counsel,

Northeast Utilities Service Company, Post Office Box 270, Hartford,

Connecticut, 06141-0270.

NRC Project Director: John F. Stolz

Pennsylvania Power and Light Company, Docket No. 50-387 Susquehanna

Steam Electric Station, Unit 1, Luzerne County, Pennsylvania

Date of amendment request: July 27, 1994

Description of amendment request: By letter dated June 15, 1992,

Pennsylvania Power and Light Company (PP&L) submitted ``Licensing

Topical Report NE-092-001, Revision 0, Power Uprate With Increased Core

Flow,'' for Susquehanna Steam Electric Station, Units 1 and 2. The

report was submitted to support future amendments to the Units 1 and 2

licenses to permit a 4.5-percent increase in reactor thermal power and

an 8-percent increase in core flow for each unit. The initial submittal

was revised and supplemented by letters of July 24, September 17, and

December 18, 1992, and January 8, January 25, April 2, August 5, August

12, and September 29, 1993. The Commission's safety evaluation on these

submittals was issued November 30, 1993 (Letter, Thomas E. Murley, NRC,

to Robert G. Byram, PP&L). The Commission concluded that the revised

(Revision 2) licensing topical report adequately supports PP&L's

proposed power uprate. The Commission also concluded that SES, Units 1

and 2, can operate safety with the proposed 8-percent increase in core

flow, the proposed 4.5-percent increase in reactor thermal power, the

corresponding 5-percent increase in main turbine inlet steam flow, and

the corresponding increases in flows, temperatures, pressures, and

capacities required in supporting systems and components at these

uprated conditions.This amendment will change several Technical

Specifications sections (listed below in the no significant hazards

consideration) for Susquehanna Steam Electric Station, Unit 1, to

increase the licensed power level from the current 3293 MWt to a new

limit of 3441 Mwt.

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 following three questions are addressed for each of the

proposed Technical Specification Changes:

1. Does the proposed change involve a significant increase in

the probability or consequences of an accident previously evaluated?

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

different kind of accident from any previously evaluated?

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

margin of safety?

Section 1.0, Definitions, Definition 1.33, Rated Thermal Power

This change redefines Rated Thermal Power as 3441 megawatts

thermal.

1. No. Neither the probability (frequency of occurrence) nor

consequences of any accident previously evaluated is significantly

affected by the increased power level because the design and

regulatory criteria established for plant equipment remain imposed

for the uprated power level. The PP&L assessment to increase the

rated thermal power level at Susquehanna SES Unit 1, followed the

guidelines of NEDC-31879P (Generic Guidelines for General

Electric Boiling Water Reactor Power Uprate,'' G.E. Nuclear Energy,

June 1991). NEDC-31879P provides generic licensing criteria,

methodology, and a defined scope of analytical and equipment review

to be performed to demonstrate the ability to operate safely at the

uprated power level which have been approved by the NRC. NE-092-001

(Licensing Topical Report for Power Uprate With Increased

Core Flow,'' Pennsylvania Power & Light Company, December 1992)

provides the description of the power uprate licensing analysis

methodology and the results of the evaluations performed to support

the proposed uprated power operation consistent with the methodology

presented in NEDC-31879P. NE-092-001 provides a description of the

power uprate licensing analysis methodology which will be used to

determine cycle specific thermal limits for Unit 1, Cycle 9 and

future cycles and concludes that an uprated power level of 3441

megawatts thermal can be achieved without significant effect on

equipment or safety analyses.

2. No. The methodology and results described above do not

indicate that a possibility for a new or different kind of accident

from any previously evaluated has been created by uprated operation.

3. No. Based on the response to Question 1 above, the

methodology and results do not indicate a significant reduction in a

margin of safety.

Section 2.1, Safety Limits

The reference to ``rated core flow'' in Technical Specification

2.1.1 and 2.1.2 has been replaced with a reference to actual core

flow. The references to ``rated core flow'' have been deleted to

avoid confusion since allowable core flow is being increased by 8%.

10 Mlbm/hr is being used in these specifications to be consistent

with other similar Technical Specification changes (Technical

Specifications 3.2.2, 4.4.1.1.1.2, 4.4.1.1.2.5, 3.4.1.3 and Figure

3.4.1.1.1-1).

1. No. The probability and consequences of accidents previously

evaluated are not affected by this change. The basis for Technical

Specification 2.1.1 is that boiling transition will not occur in

bundles if core power is less than 25% of rated thermal power,

regardless of pressure or core flow. Consequently, the specification

of less than 10% rated core flow is not crucial to the basis and,

thus, the use of 10 Mlbm/hr. is acceptable and has no effect on the

probability or consequences of a previously evaluated accident.

For Technical Specification 2.1.2, the XN-3 critical power

correlation is valid for pressure greater than or equal to 580 psig

and bundle flow greater than or equal to 0.25 Mlbm/hr-ft2. As

stated in the basis for Technical Specification 2.1.1, if vessel

downcomer water level is above TAF [top of active fuel], and core

power greater than 25%, bundle flows for potentially limiting

bundles will be greater than 0.25 Mlbm/hr-ft2 due to natural

circulation. In addition, Technical Specification 3.4.1.1.1 requires

at least one (1) recirculation loop in operation to run in Condition

2, which would produce a core flow in excess of 30 Mlbm/hr.

Therefore, core flows below about 30 Mlbm/hr-ft2 are prohibited

when the reactor is at power. Thus, the change from ``10%'' to ``10

million lbm/hr'' is acceptable and has no effect on the probability

or consequences of a previously evaluated accident.

2. No. The basis for Technical Specification 2.1.1 is that

boiling transition will not occur in bundles if core power is less

than 25% of rated thermal power, regardless of pressure or core

flow. The proposed change is not crucial to this basis. The XN-3

critical power correlation is valid for pressures greater than or

equal to 580 psig and bundle flow greater than or equal to 0.25

Mlbm/hr-ft2. The specification is based upon vessel downcomer

water level being above TAF and core power greater than 25% which

yields a bundle flow for potentially limiting bundles greater than

0.25 Mlbm/hr-ft2 due to natural circulation. Based on Technical

Specification 3.4.1.1.1, core flows below about 30 Mlbm/hr-ft2

are prohibited when the reactor is at power. Therefore, the change

to a limit of 10 Mlbm/hr is acceptable and does not create the

possibility for a new or different kind of accident from any

accident previously evaluated.

3. No. As explained above, the margin of safety has not been

reduced.

Table 2.2.1-1 (Items 2.a, 2.b, and 2.c) and Specifications

3.2.2, 3.4.1.1.2.a.2, 3.4.1.1.2.a.3, 3.4.1.1.2.a.5.b and 3.3.6-2

(Item 2.a.1, 2.c, and 2.d), APRM Flow Biased Setpoints and Allowable

Values

Although the equation for determining these setpoints does not

change as a result of the power uprate, because the setpoints in

these technical specifications are referenced to rated thermal

power, the current limits do change in that the top portion of the

operating map (power vs. reactor flow) is raised by 4.5%.

1. No. The safety analyses contained in NE-092-001 evaluated

operation at both uprated power with 4.5% higher rod lines and

increased core flow. In addition, General Electric Co. has analyzed

and received generic approval for their BWR/4 product line operation

in the Maximum Extended Operating Domain (MEOD). Operation at the

4.5% higher rod lines is bounded by the MEOD analysis. Additional

justification for this small increase in the power flow operating

range is contained in Section C.2.3 of NEDC-31984P.

Cycle specific reload analyses will evaluate operation at the

increased power vs. flow conditions (100% uprated power vs. 87% core

flow to 100% uprate power vs. 108% core flow). These analyses will

ensure that the limits established in the Core Operating Limits

Report are applicable to rated power operation from 87% to 108% core

flow.

Based on the above analyses, increasing the current limits do

not represent a significant increase in the probability or

consequences of an accident previously evaluated.

2. No. The analyses described above in response to Question 1 do

not indicate that a possibility for a new or different kind of

accident from any previously evaluated has been created by the

proposed change.

3. No. Based on the response to Question 1 above, the proposed

change does not result in a reduction in the margin of safety.

Table 2.2.1-1, Item 3, Reactor Steam Dome Pressure - High Scram

The reactor steam dome pressure-high scram trip setpoint and

allowable values are being changed to less than or equal to 1087

psig and less than or equal to 1093 psig respectively.

1. No. This scram function is designed to terminate a pressure

increase transient not terminated by direct scram or high flux

scram. The nominal trip setpoint is maintained above the reactor

vessel maximum operating pressure and the specified analytical limit

is used in the transient analyses. The analytical limit of 1105 psig

is used in the uprated transient analyses. The results of the

overpressure protection analysis indicate that the peak pressure

will remain below the 1375 psig ASME limit which meets plant

licensing requirements. In accordance with the methodology described

in NE-092-001, transient analyses will be performed using the

analytic limit and the results will be incorporated into the Core

Operating Limits Report. Therefore, this proposed change does not

involve a significant increase in the probability or consequences of

an accident previously evaluated.

2. No. The purpose of this scram function is to terminate a

pressure increase transient not terminated by direct scram or high

flux scram. The nominal trip setpoint is maintained above the

reactor vessel maximum operating pressure and the specified

analytical limit is used in the transient analysis. 1105 psig is

being used as the analytical limit in the uprated transient

analysis. The results of the overpressure protection analysis

indicate peak pressure will remain below the ASME limit of 1375 psig

which satisfies plant licensing requirements. Based upon that

result, it is concluded that the proposed change will not create the

possibility of a new or different kind of accident from any

previously evaluated.

3. No. The results of the overpressure protection analysis

indicate peak pressure will remain below the 1375 psig licensing

limit, therefore, it is concluded that the proposed change does not

result in a significant reduction in a margin of safety.

Specification 4.1.5.c, Standby Liquid Control System

This specification has been revised to require SLC [Standby

Liquid Control] pumps to develop a discharge pressure of greater

than or equal to 1224 psig.

1. No. The ability of the SLC system to achieve and maintain

safe shutdown is a function of the amount of fuel in the core and is

not directly affected by core thermal power. The SLC pump test

discharge pressure acceptance criteria are based on the lowest

relief valve setpoint. The lowest setpoint is being increased by 30

psi (to 1106) due to power uprate. Operating with increased core

flow will result in additional friction losses through the core and

a slightly larger core differential pressure (approximately 4 psi).

Therefore, increasing the SLC pump test discharge pressure

acceptance criteria ensures the capability of SLC injection. The

proposed change does not involve a significant increase in the

probability or consequences of an accident previously evaluated.

2. No. The ability of the SLC system to achieve and maintain

safe shutdown is a function of the amount of fuel in the core and is

not directly affected by core thermal power. Therefore, the proposed

change does not result in a new or different kind of accident from

any previously evaluated.

3. No. The ability of the SLC system to achieve and maintain

safe shutdown is a function of the amount of fuel in the core and is

not directly affected by core thermal power. As stated in the

response to question 1 above, the SLC pump discharge pressure

acceptance criteria are based upon the lowest relief valve setpoint.

The lowest setpoint is being increased by 30 psi. As the SLC pumps

are positive displacement pumps, the uprate will not adversely

affect the performance of the pumps to achieve proper injection.

Based on above, the proposed change does not result in a significant

reduction in a margin of safety.

Specifications 3.2.2, 4.4.1.1.1.2, 4.4.1.1.2.5, 3.4.1.3 and

Figure 3.4.1.1.1-1, Rated Core Flow References

Technical Specification 3.2.2 contains the definition of ``W''

for the flow biased APRM scram equation. The word ``rated'' is being

deleted from the definition of ``W'' since rated core flow is being

increased. The definition of ``W'' is not altered. The change is

being made for editorial purposes.

Technical Specifications 4.4.1.1.1.1.2, 4.1.1.1.2.5, 3.4.1.3,

and Figure 3.4.1.1.1-1 specify performance requirements and limits

for the Reactor Recirculation System. These specifications are

referenced to the current rated core flow. The references to ``rated

core flow'' are being replaced with actual equivalent core flows.

The specifications are equivalent and unchanged. This change is

being made for editorial purposes to avoid confusion since rated

core flow is being increased. These changes are also consistent with

the changes made in Section 2.1.

1. No. The proposed changes are editorial and do not effect the

probability or consequences of an accident previously evaluated.

2. No. The proposed changes are editorial and do not create the

possibility of a new or different kind of accident from any accident

previously evaluated.

3. No. The proposed changes are editorial and do not involve a

significant reduction in a margin of safety.

Specification Table 3.3.1-1, Note (j) and Action 6, Reactor

Protection System Instrumentation, and Table 3.3.4.2-1, Note b, End-

of-Cycle Recirculation Pump Trip System Instrumentation

The turbine first stage pressure scram bypass at 30% power in

Technical Specification Table 3.3.1-1, Note (j) and Table 3.3.4.2-1,

Note (b) is revised to indicate that the uprated equivalent

allowable value of first stage turbine pressure is 136 psig. This

value ensures that the analytical limit of 147.7 psig, which

represented 30% rated thermal power, is not exceeded.

As currently written Note (j), Note (b) and Table 3.3.1-1,

ACTION 6 are unclear and could be misinterpreted. They apply only

when RPS scram functions and End-of-Cycle Recirculation Pump Trip on

turbine main stop valves closure or control valve fast closure are

not automatically bypassed. ACTION 6 provides no guidance in the

event the bypass fails to lift when thermal power is above 30%. In

the worst case, the action statement could be interpreted literally

to allow full power operation with the RPS function still bypassed.

Such operation would violate the licensing basis analysis for the

MCPR operating limit (for the Generator Load Rejection Without

Bypass transient), which takes credit for operation of the

anticipatory scram on control valve fast closure at greater than 30%

of rated thermal power.

1. No. The revisions to Table 3.3.1-1, ACTION 6, Table 3.3.1-1,

Note (j), and Table 3.3.4-1 Note (b) clarify the current

requirements; they do not change their intent.

FSAR Chapter 15 transient analyses and reload licensing analyses

take credit for operation of the anticipatory scram function on

turbine stop valve closure and control valve fast closure for power

levels greater than 30% of rated thermal power. The proposed

revision to Table 3.3.1-1, ACTION 6 provides better assurance of the

availability of the anticipatory scram function, since the current

specifications could be interpreted literally to allow full power

operation with the RPS function bypassed.

The proposed revision to Table 3.3.1-1, Note (j) and Table

3.3.4.2-1, Note (b) does not change the operation of the RPS and

EOC-RPT bypasses on turbine stop valve closure and control valve

fast closure below 30% power. The turbine first stage pressure

switches will still be calibrated in the same manner, and, by

procedure, the reactor operator will not exceed 30% power if the

trip bypass annunciator does not clear.

The setpoints for the RPS and EOC-RPT bypass functions were

selected to allow sufficient operating margin to avoid scrams during

low power turbine generator trips. As discussed in NEDC-31894P,

Section F4.2(c) and in Section 5.1.2.8 of NEDC 31948P, this small

absolute setpoint increase maintains the safety basis for the

setpoint.

Based on the above, the proposed changes do not involve a

significant increase in the probability or consequences of an

accident previously evaluated.

2. No. The changes proposed are clarifications and do not change

specification intent. The proposed change to Table 3.3.1-1, Action 6

provides better assurance of the availability of the anticipatory

scram function as the specification could currently be interpreted

to allow full power operation with the RPS function bypassed. The

proposed changes to Table 3.3.1-1, Note (j) and Table 3.3.4-1, Note

(b) do not change the operation of the RPS and EOC-RPT bypasses on

turbine stop valve closure and control valve fast closure below 30%

power. Therefore, the possibility for a new or different kind of

accident is not created.

3. No. The proposed changes are clarification and do not change

intent. Operation of the RPS and EOC-RPT bypasses on turbine stop

valve closure and control valve fast closure below 30% power is not

changed. Therefore, there is no reduction in the margin of safety.

Specification Table 3.3.2-2, Item 3.d, Main Steam Line Flow

Differential Pressure Setpoint

The main steam line flow high differential pressure setpoint and

allowable value are revised to read trip setpoint and allowable

values of 113 psid and 121 psid respectively. Footnote ``**'' was

added to Table 3.3.2-2 to indicate that these values will be

confirmed during the power uprate start-up testing. If revisions to

the setpoint and allowable value are required, they will be

forwarded to the Commission for approval within 90 days of

completion of the test program.

1. No. The main steam line flow high differential pressure

setpoint changes reflect the redefinition of rated main steam line

flow that occurs with power uprate. The allowable value is

maintained at the same percentage of rated steam flow as the

differential pressure changes due to the increased uprate steam

flow. The analytical limit of 140% of uprated steam flow is

maintained for the uprated analyses. The relationship between the

allowable value and the analytical limit was retained to ensure that

a trip avoidance margin is maintained for the normal plant testing

of MSIV's and turbine stop valves. The increase in the absolute

value of the trip setpoint still provides a high assurance of

isolation protection for a main steam line break accident which

satisfies the original intent of the design. Therefore, the proposed

changes do not involve a significant increase in the probability or

consequences of an accident previously evaluated.

2. No. The increase in the absolute value of the trip setpoint

still provides a high assurance of isolation protection for the main

steam line break accident which satisfies the original intent of the

design and, therefore does not create the possibility of a new or

different kind of accident from any accident previously evaluated.

3. No. The increase in the absolute value of the trip setpoint

still provides a high assurance of isolation protection for a main

steam line break accident which satisfies the original intent of the

design and, therefore, does not involve a significant reduction in a

margin of safety.

Specification Table 3.3.2-2, Item 4.f, Isolation Actuation

Instrumentation Setpoints

The RWCU system flow-high isolation trip setpoint and allowable

value are being changed. System flow is being increased by 10% to

maintain reactor coolant water chemistry at a level equal to pre

uprate levels. The isolation setpoint change is being made to

adequately maintain operating margin between normal process values

and the isolation setpoints.

1. No. The basis for the RWCU flow-high isolation is to ensure a

RWCU System isolation in case of a pipe break. The high flow

setpoint is set high enough to avoid spurious trips from normal

operating transients but low enough to ensure an isolation during a

pipe break. The proposed Technical Specification limits will result

in a negligible reduction in the margin between the RWCU isolation

setpoint and the 4350 gpm flow postulated during a RWCU line break

and will avoid spurious isolations. Therefore, the proposed change

does not involve a significant increase in the probability or

consequences of an accident previously evaluated.

2. No. As stated above, the proposed change will result in only

a negligible reduction in the margin between the RWCU isolation

setpoint while avoiding spurious isolation. Therefore, this change

maintains the original design intent and does not create the

possibility of a new or different kind of accident from any accident

previously evaluated.

3. No. See 1. above.

Specification Table 3.3.2-2, Items 5.a and 6.1, Isolation

Actuation Instrumentation Setpoints

The HPCI and RCIC Steam Line Flow-High Technical Specifications

are being changed to account for changes in steam conditions and

flows that result from operation at the uprated conditions. The

setpoint and allowable value for HPCI Steam Line Flow-High isolation

are less than or equal to 387 inches H2O setpoint and allowable

value for the RCIC Steam Line Delta Pressure-High isolation are less

than or equal to 188 inches H2O and less than or equal to 193

inches H2O respectively.

1. No. The bases for these setpoints are contained in the

General Electric Design Specification Data Sheets for the HPCI and

RCIC systems. The Design Specification Data Sheets specify that the

setpoint and allowable value be set so that the isolation occurs at

greater than 272% normal steam flow and less than 300% steam flow.

General Electric has historically seen start-up transients as high

as 272% of normal steam flow. Setting the isolation above this value

prevents spurious isolations and ensures availability of the system

and its safety function. Setting the isolation at less than or equal

to 300% of normal flow insures that the isolation will occur if a

steam line should rupture.

The existing setpoints were calculated using information

obtained during the recent surveillance tests. The revised setpoints

and allowable values were calculated using the current system

performance and adjusted for uprate conditions in accordance with

additional guidance provided in General Electric Information Letter

(SIL) No. 475, Revision 2, NEDC-31336, ``General Electric Setpoint

Methodology,'' and GE Letter SPU-9378, ``HPCI and RCIC Steam Line

Break Detection Setpoints''.

Based on the above approach, the proposed change does not

involve a significant increase in the probability or consequences of

an accident previously evaluated.

2. No. The setpoint and allowable value are set so that

isolation occurs at greater than 272% normal steam flow and less

than 300% steam flow. Setting the isolation at less than or equal to

300% of normal flow ensures that the isolation will occur if a steam

line rupture should occur. Therefore, no new events are postulated

as a result of this change.

3. No. The proposed change does not involve a significant

reduction in a margin of safety as the setpoint and allowable value

are set to isolate at greater than 272% normal steam flow and less

than 300% steam flow which are the setpoints contained in the

General Electric Design Specification Data Sheets for the HPCI and

RCIC systems.

Specification Table 4.3.2.1-1, footnote ``**''

The footnote is being changed to delete reference to reactor

pressure.

1. No. The original purpose of Footnote ``**'' to Technical

Specification Table 4.3.2.1-1 was to describe the functioning of the

permissive circuitry that allowed the MSIV low condenser pressure

isolation to be bypassed. The original circuitry required the Mode

Switch not be in Run, the Turbine Stop Valves closed, and reactor

pressure to be above setpoint. In the start-up phase of the

Susquehanna Units, General Electric deleted the reactor pressure

setpoint input to the bypass circuitry. Therefore, this change is

being made to make the footnote conform to the installed

configuration. The revised footnote is the same as found in the BWR/

4 Standard Technical Specifications (NUREG 1433). This change is

editorial in nature and, therefore, does not involve a significant

increase in the probability or consequences of an accident

previously evaluated.

2. No. Based on the response to Question 1 above, the proposed

change does not create the possibility of a new or different kind of

accident from any accident previously evaluated.

3. No. Based on the response to Question 1 above, the proposed

change does not involve a significant reduction in a margin of

safety.

Specification Table 3.3.6-2, Item 1.a and Specification

3.4.1.1.2.a.5.a, Rod Block Monitor Flow Biased Rod Blocks

The Rod Block Monitor (RBM) flow biased rod blocks are being

changed as follows:

a. Technical Specification Table 3.3.6-2, Item 1.a is revised to

read trip setpoint and allowable values of less than or equal to

0.63 W + 41% and less than or equal to 0.63 W + 43%, respectively.

b. Technical Specification 3.4.1.1.2.a.5.a is being revised to

read trip setpoint and allowable values of less than or equal to

0.63 W + 35% and less than or equal to 0.63 W + 37%, respectively.

1. No. These Technical Specification changes do not represent a

change from current limits. The change reflects the rescaling made

necessary by the re-definition of rated thermal power.

The RBM flow biased rod blocks are used in the Rod Withdrawal

Error (RWE) analysis. In order to maintain Critical Power Ratio

(CPR) margins similar to previous Susquehanna cycles, the flow

biased rod blocks were changed in terms of megawatts thermal but the

change was not appreciable. The rescaling of the RBM flow biased rod

block to reflect the re-definition of Rated Thermal Power maintains

the same level of protection as previously provided. Therefore, the

proposed change does not involve a significant increase in the

probability or consequences of an accident previously evaluated.

2. No. These changes do not represent a change from current

limits but are rather a rescaling made necessary by the re-

definition of rated thermal power.

3. No. These changes do not represent a change from current

limits but are rather a rescaling made necessary by the re-

definition of rated thermal power. The rescaling of the RBM flow

biased rod block maintains the same level of protection as

previously provided.

Specification Table 3.3.6-2, Item 2.a, Control Rod Block

Instrumentation Setpoints

The APRM rod block upscale value has been changed to add a high

flow clamp setpoint at 108% with a high flow clamped allowable value

at 111%.

1. No. The addition of the high flow clamp to the flow biased

APRM rod block function maintains the normal margins between the rod

block and the scram power levels in the increased core flow regions.

When the reactor core flow is greater than 100 million lbm/hr, the

APRM clamp provides an alarm to help the operator avoid scrams while

operating in the ICF region. This action does not involve a

significant increase in the probability or consequences of an

accident previously evaluated.

2. No. The changes maintain the normal margins between the rod

block and the scram power levels in ICF regions. The clamp provides

an alarm to avoid scrams in the ICF region.

3. No. The changes maintain the normal margins between the rod

block and the scram power levels.

Specification Table 3.3.6-2, Item 6.a, Reactor Coolant System

Recirculation Flow Upscale Rod Block Setpoint and Allowable Value

Change

The reactor coolant system recirculation flow upscale rod block

setpoint and allowable value are being increased to 114/125

divisions of full scale and 117/125 divisions of full scale

respectively.

1. No. The Reactor Coolant System recirculation flow upscale rod

block setpoint and allowable value are being increased to allow

operation in the ICF region. The 114/125 divisions setpoint and 117/

125 divisions allowable value, specified by General Electric, are

based on BWR operating history.

The purpose of the Reactor Coolant System recirculation flow

upscale rod block is to prevent rod movement when an abnormally high

increase in reactor recirculation flow exists. An increase in

reactor recirculation flow causes an increase in neutron flux that

results in an increase in reactor power. However, this increase in

neutron flux is monitored by the Neutron Monitoring System that can

provide a rod block. No design basis accident or transient analysis

takes credit for rod block signals initiated by the Reactor Coolant

Recirculation System. Therefore, this change does not increase the

probability or consequences of an accident previously evaluated.

2. No. Rod block signal initiation by the Reactor Coolant

Recirculation System is not taken credit for in the mitigation of a

design basis accident or in any transient analysis.3. No. Rod block

signal initiation by the Reactor Coolant Recirculation System is not

taken credit for in any transient analysis or in the mitigation of a

design basis accident.

Specification 4.4.1.1.1.2 and 4.4.1.1.2.5 Reactor Coolant System

The reactor recirculation pump motor generator set scoop tube

electrical and mechanical overspeed stop setpoints are being

increased to a core flow of 109.5 million lbm/hr. and 110.5 million

lbm/hr., respectively.

1. No. The reactor recirculation pump motor generator set scoop

tube stops are being increased to allow operation at core flows in

the ICF region of up to 108 million lbm/hr.

The electrical stop is maintained above the maximum operating

core flow and below the mechanical stop. The 109.5 million lbm/hr.

electrical stop setpoint, specified by General Electric, is based on

BWR operating history. The electrical stop is a system design

feature and is not used in any safety analyses.

The 110.5 million lbm/hr. mechanical stop setpoint is used in

transient analysis to limit core flow during a recirculation pump

controller failure. The 110.5 million lbm/hr. mechanical stop

setpoint, specified by General Electric, is also based on BWR

operating history. The cycle specific analyses, performed for power

uprate, used the 110.5 million lbm/hr. mechanical stop setpoint.

Based on the above, this change does not involve a significant

increase of the probability or consequences of an accident

previously evaluated.

2. No. Increasing the reactor recirculation motor generator set

scoop tube electrical and mechanical overspeed stop setpoints is

being done to allow operation at core flows in the ICF region up to

108 Mlbm/hr. The electrical stop setpoint is a design feature and is

not used in any safety analysis. The mechanical stop setpoint is

used in transient analysis to limit core flow during a recirculation

pump controller failure. Changing of this setpoint was considered in

appropriate transient analyses, and will not create the possibility

of a new or different kind of accident from any previously

evaluated.

3. No. See 1. above. This change does not significantly reduce

the margin of safety.

Specification Figure 3.4.1.1.1-1, Thermal Power Restrictions

This figure has been redrawn to reflect the new definition of

Rated Thermal Power to retain the same stability operating

restrictions in terms of megawatts thermal as were previously

described by this graph.

1. No. The core thermal hydraulic stability curve and associated

bases are maintained at the current rod lines and power levels.

Those values are redefined to reflect the redefinition of rated

thermal power. Since the current operating restrictions are

maintained, power uprate has no detrimental effect on the level of

protection provided by these Technical Specifications. This position

is consistent with NEDC-31894P, Section 5.3.3 and with NEDC-31984P,

Section 3.2.

2. No. The core thermal hydraulic stability curve and associated

bases are maintained at the current rod lines and power levels.

Those values are changed to reflect the redefinition of rated

thermal power. Since the current operating restrictions are

maintained, power uprate has no detrimental effect on the level of

protection provided and does not create the possibility for a new or

different kind of accident.

3. No. The core thermal hydraulic stability curve and associated

bases are maintained at the current rod lines and power levels.

Those values are redefined to reflect the redefinition of rated

thermal power. Since the current operating restrictions are

maintained, there is no detrimental effect on the level of

protection provided, and therefore no significant decrease in any

margin of safety.

Specifications 3.4.1.1.2.5, 3.4.1.1.2.6, Reactor Coolant System,

Recirculation Loops - Single Loop Operation

Specification 3.4.1.1.2.5 is being renumbered to 3.4.1.1.2.6. A

new specification 3.4.1.1.2.5 is being added to specify that a 0.70

LHGR multiplier has been applied to Specification 3.2.4 when in

single recirculation loop operation.

1. No. Operation with one recirculation loop out of service is

allowed, but it is not considered a normal mode of operation. Single

loop operation (SLO) is a special operational condition when only

one of the two recirculation loops is operable. In this operating

condition, the reactor power will be limited to less than 80% of

rated by the maximum achievable core flow, which is typically less

than 60% of rated core flow. A postulated LOCA occurring in the

active recirculation loop during SLO would cause a more rapid

coastdown of the recirculation flow than would occur in two loop

operation, where one active loop would remain intact. This rapid

coastdown causes an earlier boiling transition and deeper

penetration of boiling transition into the bundle, which tends to

increase the calculated PCT. However, the PCT effects of early

boiling transition are substantially offset by the mitigating effect

of the lower power level achievable at the start of such an event.

The SAFER/GESTR-LOCA analysis results for Susquehanna for SLO and

two loop operation are well below 2200 deg.F and are documented in

NEDC-32064P-1, Revision 1, ``Power Uprate with Increased Core Flow

Safety Analysis for Susquehanna 1 and 2'', GE Nuclear Energy, July

1993.

The ECCS performance for Susquehanna under SLO was evaluated

using SAFER/GESTR-LOCA. Calculations for the DBA were performed

using both nominal and Appendix K inputs. The SLO SAFER/GESTR-LOCA

analysis for the DBA assumes that there is essentially no period of

recirculation pump coastdown. Thus, dryout is assumed to occur

simultaneously at all axial locations of the hot bundle shortly

after initiation of the event. Dryout is assumed to occur in one

second for the nominal case and 0.1 second for the Appendix K case.

These assumptions are very conservative and provide bounding results

for the DBA under SLO.

The two-loop Appendix K break spectrum documented in NEDC-

32064P-1 is representative of SLO because the two-loop spectrum was

analyzed assuming a one second dryout time for all axial locations

of the hot bundle. As shown by the two-loop break spectrum, the DBA

is the limiting case for SLO. With breaks smaller than the DBA,

there is a longer period of nucleate and/or film boiling prior to

fuel uncovery to remove the fuel stored energy.

An LHGR multiplier of 0.70 will be imposed when the plant is in

SLO. As shown in Table 5-6 of NEDC-32064P-1, the SLO results are

less limiting (i.e., lower PCT's) than the results for the two loop

DBA LOCA.

Thus, the licensing PCT is based appropriately on two loop

operation rather than SLO.

2. No. The licensing PCT is based upon two loop operation rather

than SLO, thus the proposed change does not create the possibility

of a new or different kind of accident from any previously

evaluated.

3. No. Based on the response to Question 1 above, the proposed

change does not involve a significant reduction in a margin of

safety.

Specification 4.4.1.1.2.3, Reactor Coolant System

Footnote **** to this Specification is being changed to

reference the power uprate startup test program.

1. No. This footnote provided a mechanism for changing the power

limits specified if the results of the initial startup test program

determined that it was necessary. The footnote is being modified to

allow operation at uprated power with the present power limits.

Should the power uprate startup test program determine a need to

change the power limits they will be submitted to the Commission

within 90 days as required by the revised footnote. This is

consistent with the original BWR startup test program philosophy and

does not involve a significant increase in the probability or

consequences of an accident previously evaluated.

2. No. See 1. above; this change is administrative in nature and

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

accident from any previously evaluated.

3. No. See 1. above; this change is administrative in nature and

does not involve a significant reduction in a margin of safety.

Specification 3.4.2, Reactor Coolant system, Safety Relief

Valves

The safety relief valve specification is being changed to reduce

the number of setpoint groups from 5 to 3. Two valves will be set at

1175 psig plus or minus 1%, 6 will be set at 1195 psig plus or minus

1%. Also, the number of Operable safety valves is being increased

from 10 to 12.

1. No. This change does not increase the probability of

occurrence of an accident previously evaluated as, with one

exception, the accidents described in FSAR Sections 5.2.2, 7.2.3,

15.1, 15.2 and 15.3 do not document any cases where the SRV's are

designated as the cause or initiator of an accident. The exception

is inadvertent safety relief valve opening which results in a

decrease in reactor coolant inventory and/or reactor coolant

temperature. The revised setpoints and proposed groupings will not

increase the probability of occurrence of this type of accident.

The change does not increase the probability of occurrence of a

malfunction of equipment important to safety as previously evaluated

in the FSAR. The margin between peak allowable pressure and the

maximum safety setpoint is unchanged. The reactor vessel and

components were evaluated for the setpoint change to assure

continued compliance with the structural requirements of the ASME

Code. Analysis was performed on the effects of the setpoint change

for the design conditions, the normal and upset conditions and the

emergency and faulted conditions. The increasing RPV dome pressure

does not affect the design condition and, therefore, stresses remain

unchanged.

The proposed change will also not adversely affect HPCI and RCIC

system performance.

There is no indication that changed setpoints contribute to an

increase in probability of SRV malfunction. Reduction in the simmer

margin will be compensated for by more stringent leak test

requirements during valve refurbishment.

2. No. This change does not involve any hardware changes or

changes in system function. Relief and safety setpoints are only

slightly increased and the maximum safety setpoint remains

unchanged, thus the margin between peak allowable pressure and the

setpoint remains unchanged.

3. No. The technical specifications were reviewed for margins of

safety applicable to the components and systems affected by the

change. Analysis has been performed that demonstrates that reactor

pressure will be limited to within ASME Section III allowable values

for the worst case upset transient. The margin of safety is inherent

in the ASME Section III allowable pressure values.

Specification 3.4.3.2.d, Reactor Coolant System, Operational

Leakage

This specification is being revised to indicate that the 1 gpm

leakage rate limit currently applicable applies at the uprated

maximum allowable pressure of 1035 psig, plus or minus 10 psig.

1. No. The steam dome pressure for leakage is being increased by

35 psig to 1035 psig (reactor design pressure). This pressure is

chosen on the basis of steam line pressure drop characteristics and

excess steam flow capability of the turbine observed during plant

operation up to the current rated power level. Increasing the

leakage rate pressure to 1035 psig is consistent with the expected

uprated operating pressure. Increasing the reactor steam dome

pressure has been analyzed and found to be within allowable limits.

Maintaining the leakage rate limit at 1 gpm does not involve a

significant increase in the probability or consequences of an

accident previously evaluated.

2. No. This change does not involve any hardware changes or

change in safety function. The reactor steam dome pressure has been

analyzed and found to be within allowable limits.

3. No. Maintaining leakage the rate limit at 1 gpm is

conservative and does not involve a reduction in the margin of

safety.

Specifications 3.4.6.2 and 4.4.6.2, Reactor Coolant System,

Reactor Steam Dome

The reactor steam dome pressure limits have been changed to 1050

psig.

1. No. Operating pressure for uprated power is increased by a

minimum amount necessary to assure that satisfactory reactor

pressure control is maintained. The operating pressure was chosen on

the basis of steam line pressure drop characteristics and excess

steam flow capability of the turbine observed during plant operation

up to the current rated power level. Satisfactory reactor pressure

control requires an adequate flow margin between the uprated

operating condition and the steam flow capability of the turbine

control valves at their maximum stroke. An operating dome pressure

of 1032 psig is expected and is being assumed in the transient

analyses. The 1050 psig limit was chosen to maintain an adequate

level of operating flexibility while maintaining an adequate

distance from the high pressure scram for trip avoidance. This limit

is the initial pressure value used in the overpressure protection

safety analysis for power uprate, for which all licensing criteria

have been met. Therefore, this change does not involve a significant

increase in the probability or consequences of an accident

previously evaluated.

2. No. Based on the response to Question 1. above, the proposed

change does not create the possibility of a new or different kind of

accident from any previously evaluated.

3. No. As described in 1. above, the 1050 psig limit was chosen

to maintain an adequate level of operating flexibility while

maintaining an adequate distance from the high pressure scram. This

limit is the initial pressure value used in the over pressure

protection safety analysis for power uprate, for which all licensing

criteria have been met. Therefore, the proposed change does not

involve a significant reduction in a margin of safety.

Specification 4.5.1.b.3, Emergency Core Cooling Systems

This specification has been revised to permit a test line

pressure for the flow surveillance of greater than or equal to 1140

psig at nominal reactor operating conditions.

1. No. Currently, the HPCI pump test acceptance criteria

discharge pressure is greater than or equal to 1266 psig. This is

based, in part, on the lowest SRV setpoint of 1146 psig plus a 1%

tolerance and line flow losses. For this test, the HPCI turbine is

supplied with steam at the nominal operating reactor pressure of 920

+140/-20 psig. Therefore, the test requires the HPCI pump/turbine to

produce an output that exceeds that which would be commensurate with

the input conditions. Stated differently, HPCI would be required to

develop a pump discharge pressure associated with a steam dome

pressure of 1187 psig (1175 plus or minus 1% psig), while being

supplied with a steam dome pressure as low as 900 psig.

The purpose of this specification is to demonstrate that the

system is capable of producing the required flow at the required

pressure. The concern with this approach is that while it

demonstrates the required capability by achieving the actual

Technical Specification value, it requires the pump turbine to

``over perform''. It also reduces the margin available to compensate

for normal wear and tear [that] occurs and is monitored under the

ASME Section XI Pump and Valve Test Program. Power uprate will be

further increasing the demand because of the increase in reactor

steam dome pressure.

The intent of Surveillance 4.5.1b.3 is to demonstrate that the

HPCI System will produce its design flow rate at an expected reactor

pressure during a LOCA. Confirmation of the capability to achieve

the required flow and pressure can be satisfactorily demonstrated

without requiring the pump/turbine to ``over perform''. This can be

done by producing the nominal operating design pressure from the

pump with steam supplied to the turbine at nominal reactor operating

pressure. From these conditions extrapolation via pump affinity laws

will show the pump discharge pressure that would be developed at

emergency reactor operation conditions (i.e. lowest SRV setpoint).

This value could then be compared to the calculated value required

for assuring adequate core cooling in both SSES specific and generic

evaluations. The HPCI System has been evaluated and shown to be

capable of achieving the required pressure and flow conditions for

power uprate.

Applying the method of pump affinity laws, the new Technical

Specification pump discharge pressure would become greater than or

equal to 1140 psig. This value is determined based on the maximum

allowable test steam dome pressure of 920 + 140 = 1060 psig, plus

head losses. Through the use of pump affinity laws it has been shown

by calculation that achieving a value of 1140 psig at nominal

reactor operating conditions will produce the required flow and

pressure during emergency conditions.

Therefore, the Technical Specification HPCI pump discharge

pressure at power uprate conditions is changed to greater than or

equal to 1140 psig.

2. No. The methodology and the supporting change described above

in the response to Question 1 above do not alter the function nor

the operation of the HPCI system. Therefore, they do not create the

possibility of a new or different kind of accident from any accident

previously evaluated.

3. No. The methodology and the supporting change described above

in response to Question 1 do not involve a significant reduction in

a margin of safety.

Specification 5.4.2, Design Features, Reactor Coolant System,

Volume

This specification is being changed to show that the nominal

Tave is being changed from 528 deg.F to 532 deg.F. This change

is being made to reflect the higher average saturation temperature

that results from a 30 psi increase in reactor design pressure.

1. No. The effects of power uprate have been evaluated to ensure

that the increase in system temperatures causes minor increases in

thermal loadings on pipe supports, equipment nozzles, and in-line

components. The results of analyses show that at uprated conditions

all ASME components will satisfy design specification requirements

and code limits when evaluated to the rules of Subsection NB-3600 of

the ASME Boiler and Pressure Vessel Code Section III. The effects of

thermal expansion as a result of power uprate were found to be

insignificant. Therefore, this change does not involve a significant

increase in the probability or consequences of an accident

previously evaluated.

2. No. Increases in system temperatures as a result of power

uprate have been evaluated to show that increase in thermal loadings

on pipe supports, equipment nozzles and in-line components are

minor. Analysis shows that at all uprated conditions all ASME

components will satisfy design specification requirements and code

limits when evaluated to the rules of subsection NB-3600 of Section

IV to the Boiler and Pressure Vessel Code. The effects of power

uprate with respect to thermal expansion were found to be

insignificant and, therefore, not found to create the possibility of

a new or different kind of accident.

3. No. As stated above, the effects of thermal expansion as a

result of power uprate were found to be insignificant. Consequently,

the nominal increase in Tave does not involve a significant

reduction in a margin of safety.

Specification Table 5.7.1-1, Component Cyclic or Transient

Limits

This specification is being changed to raise the upper limit for

a heat cycle from 546 deg.F to 551 deg.F. This change is being made

to reflect the higher average saturation temperature that results

from a 30 psi increase in reactor design pressure.

1. No. The purpose of this specification is to limit the number

of heatup and cooldown cycles. The effects of power uprate have been

evaluated to ensure that the reactor vessel components continue to

comply with the existing structural requirements of the ASME Boiler

and Pressure Vessel Code. The analyses were performed for the

design, normal, upset, emergency and faulted conditions. The

increase in the temperature limitation is not significant with

respect to the affect it has upon the RPV and associated components.

2. No. The effects of uprating power have been evaluated for the

design, normal, upset, emergency and faulted conditions to ensure

that the reactor vessel components continue to comply with the

existing structural requirements of the ASME Boiler and Pressure

Vessel Code. The increase in the temperature limitation has been

found not to be significant and, therefore, does not create the

possibility of a new or different kind of accident from any

previously evaluated.

3. No. This specification is intended to limit the number of

heatup/cooldown cycles. The increase in the temperature limitation

has not been found to be significant with respect to its effects

upon the RPV and its associated components and, therefore, does not

significantly reduce the margin of safety.

Specification 6.9.3.2, Core Operating Limits Report

Administrative Control Section 6.9.3.2 describes and lists

topical reports that are used to determine core operating limits.

Topical reports 15 through 19 are LOCA methodology reports and are

being deleted. These reports describe Siemens LOCA methodology. As

stated in Reference 1, the GE SAFER/GESTR LOCA methodology is being

used for this uprated cycle. In addition, other minor methodology

changes were made for power uprate transient analysis. GE topical

report NEDC-32071P, PP&L topical report NE-092-001 and the NRC

Safety Evaluation Report on the PP&L power uprate licensing topical

are proposed to be added as Topical Reports No. 15, 16, and 17,

respectively.

1. No. These changes are editorial in nature in that only the

references to documents are being changed. The methodology used to

determine core limits have been previously reviewed and approved by

the NRC.

2. No. See the response to Question 1 above.

3. No. See the response to Question 1 above.

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: Osterhout Free Library, Reference

Department, 71 South Franklin Street, Wilkes-Barre, Pennsylvania 18701

Attorney for licensee: Jay Silberg, Esquire, Shaw, Pittman, Potts

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

NRC Project Director: Mohan C. Thadani, Acting

Pennsylvania Power and Light Company, Docket Nos. 50-387 and 50-388

Susquehanna Steam Electric Station, Units 1 and 2, Luzerne County,

Pennsylvania

Date of amendment request: July 27, 1994

Description of amendment request: This amendment will change the

definition of a CORE ALTERATION included in Technical Specification

Section 1.0 for each unit to allow movement and replacement of local

power range monitors and control rods in a defueled cell. The new

definition is consistent with the Improved Standard Technical

Specifications.

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. In the submittal, the licensee stated that:

I. This proposal does not involve a significant increase in the

probability or consequences of an accident previously evaluated.

The proposed change eliminates two previous evolutions, LPRM and

Control Rod movement from a defueled cell, from being considered

CORE ALTERATIONS. Thus the issue is whether the elimination of these

constraints could contribute to a significant increase in the

probability or consequences of a reactivity event.

Adding local power range monitors to the list of detectors which

can be moved without invoking CORE ALTERATION requirements allows

for the removal of these detectors for repair and replacement.

Movement of these components does not impact the reactivity of the

core. Therefore, allowing the movement of these detectors without

invoking CORE ALTERATION provisions, does not contribute to a

significant increase in the probability or consequences of a

reactivity event.

Removal of a Control Rod from a defueled cell results in a

negligible increase in core reactivity. Appropriate Technical

Specification controls and refueling interlocks are applied during

the fuel movements preceding the control rod removal to protect from

or mitigate a reactivity excursion event. In addition, the design of

a control rod precludes its replacement without all fuel assemblies

in the cell removed. Therefore, allowing the movement of control

rods from a defueled cell without invoking CORE ALTERATION

provisions, does not contribute to a significant increase in the

probability or consequences of a reactivity event.

The proposed Technical Specification change to adopt the revised

CORE ALTERATION definition (NUREG 1433, as amended) does not effect

the probability or consequences of an accident previously evaluated.

II. This proposal does not create the possibility of a new or

different kind of accident from any accident previously evaluated.

The proposed change eliminates two previous evolutions, LPRM and

Control Rod movement from a defueled cell, from being considered

CORE ALTERATIONS. Thus the issue is whether the elimination of these

constraints could create the possibility of a new or different kind

of accident from any accident previously evaluated.

For local power range monitors, Technical Specification 3/4.3.1

defines the minimum number of LPRMs required to be maintained

operable in OPCON 5 and during Shutdown Margin Demonstration. The

addition of LPRMs as an exclusion under the CORE ALTERATION

definition does not change the operability requirements for the

LPRMs under Technical Specification 3/4.3.1. Thus the ability of the

LPRMs to perform their monitoring function is not affected by the

proposed CORE ALTERATION definition change. In addition, movement of

these components does not impact the reactivity of the core.

Therefore, allowing the movement of these detectors without invoking

CORE ALTERATION provisions, does not create the possibility of a new

or different kind of accident from any accident previously

evaluated.

For Control Rods, in the unlikely event that the wrong control

rod was inadvertently withdrawn from a fueled cell during evolutions

which were not intended to be CORE ALTERATIONS, adequate protective

measures are provided by design and core monitoring instrumentation

required to be operable in OPCON 5. Withdrawal of a single control

rod from a cell containing fuel is bounded by Shutdown Margin

analysis and demonstration. However, assuming the inadvertent

control rod withdrawal resulted in a significant reactivity

addition, the Reactor Protection System (RPS) would respond by

inserting all control rods via the Scram function. The RPS monitors

for recriticality during OPCON 5 with SRMs (except during specific

controlled evolutions), IRMs, and APRMs. The Scram circuitry is

completely redundant from the insert and withdrawal circuitry for

the control rods. Therefore, allowing the movement of control rods

from a defueled cell without invoking CORE ALTERATION provisions,

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

accident from any accident previously evaluated.

The proposed Technical Specification change to adopt the revised

CORE ALTERATION definition (NUREG 1433, as amended) does not create

the possibility of a new or different kind of accident from any

accident previously evaluated.

III. This change does not involve a significant reduction in a

margin of safety.

To evaluate the potential effect on safety margin, the proposed

change was evaluated as to its effect on Shutdown Margin. Shutdown

Margin defines the amount of reactivity by which the reactor is

subcritical, and thus is a measure of the safety margin in avoiding

unanticipated criticality events.

The movement of LPRMs does not impact the reactivity of the

core, and thus does not reduce the Shutdown Margin. Removal of a

Control Rod from a defueled cell results in a negligible increase in

core reactivity. Therefore, the removal of a Control Rod from a

defueled cell will have a negligible effect on the core Shutdown

Margin. Per Technical Specification 3/4.9.10.2(c), adequate core

Shutdown Margin must exist during refueling when multiple control

rods and the surrounding fuel assemblies are removed from the core.

Appropriate Technical Specification controls and refueling

interlocks are applied during the fuel movements preceding the

control rod removal to protect from or mitigate a reactivity

excursion event. In addition, the core is analyzed to maintain

Shutdown Margin even with the withdrawal of the highest worth rod

from a fueled cell.

The proposed Technical Specification change to adopt the revised

CORE ALTERATION definition (NUREG 1433, as amended) 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 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: Osterhout Free Library, Reference

Department, 71 South Franklin Street, Wilkes-Barre, Pennsylvania 18701

Attorney for licensee: Jay Silberg, Esquire, Shaw, Pittman, Potts

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

NRC Project Director: Mohan Thadani, Acting

Philadelphia Electric Company, Docket Nos. 50-352 and 50-353,

Limerick Generating Station, Units 1 and 2, Montgomery County,

Pennsylvania

Date of amendment request: July 20, 1994

Description of amendment request: The amendments would raise the

Steam Leakage Detection system set-points that isolate the High

Pressure Coolant Injection System (HPCI) and Reactor Core Isolation

Cooling (RCIC) system equipment on high equipment room temperature and

high delta temperature. The amendments are supported by a Limerick

Generating Station modification to increase the environmental

qualifications limits of the HPCI and RCIC systems to allow the systems

to remain operable when equipment room cooling is unavailable.

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. The proposed Technical Specifications changes do not involve

a significant increase in the probability or consequences of an

accident previously evaluated.

Those accident which are potentially impacted by these changes

are any accident or events that require the isolation of the HPCI or

RCIC system steam supply lines. This would include gross failures

(pipe breaks) or significant leaks (pipe cracks) in steam lines.

Minor leaks that do not significantly affect the environment in the

equipment compartments are only considered with regard to being

potential precursors to the development of a larger crack or break.

The ability to detect small steam leaks is not dependent on the

isolation instrumentation and the proposed changes to the isolation

instrumentation will not impact the detection methods.

The proposed TS changes will not increase the probability of an

accident since the changes will only increase the trip set-points of

the instrumentation which detect increases in the temperature in the

HPCI and RCIC equipment rooms. The physical establishment and

setting of the proposed set-points of these accident detection and

mitigation instruments will have no direct physical impact on the

plant's normal operating conditions. This instrumentation is

normally in a ``monitoring mode,'' and is not actively supporting

normal plant operation. Therefore, the proposed set-points can have

no impact on the operating plant that would make an accident more

likely to occur.

Two perspectives were evaluated regarding the potential impact

on the consequences of accidents. One case is the impact on

accidents which do not require HPCI or RCIC steam line isolation,

but that may require the operation of the HPCI or RCIC Systems. The

other case is the impact resulting from HPCI and RCIC steam line

break accidents.

In the first case, the proposed changes to the set-points of

these accident mitigation instruments will have no direct physical

impact on the plant's accident response, except during the HPCI or

RCIC pipe break accidents. During all other pipe breaks or

accidents, the bounding peak HPCI and RCIC equipment compartment

temperatures will still be at least 35 deg.F below the proposed TS

lower allowable values (i.e., 218 deg.F and 198 deg.F,

respectively), and the isolation instrumentation will remain in a

``monitoring mode.'' The isolation instrumentation will only be

required to continue to passively monitor the HPCI and RCIC

compartment temperatures and will meet the design basis by not

inadvertently isolating the HPCI or RCIC systems.

In the second case, the HPCI and RCIC pipe break accidents

described in LGS, Updated Final Safety Analysis Report (UFSAR)

Section 3.6 ``Protection Against Dynamic Effects Associated with the

Postulated Rupture of Piping,'' determine the peak pressures and

temperatures for the affected compartments. These peak pressures for

the HPCI and RCIC breaks are the bounding pressures for breaks in

these lines and, since they occur quickly, they are unaffected by

the leak detection and isolation actuation systems. The peak

pressures predicted in the UFSAR for the largest HPCI and RCIC steam

line breaks, in the HPCI, RCIC and isolation valve compartments, are

the bounding values for breaks of all sizes in these compartments.

In addition, the peak temperatures are not affected by the proposed

changes to the isolation actuation set-points. Therefore, the

isolation of the HPCI and RCIC steam lines following a HPCI or RCIC

steam line guillotine break is not dependent on the temperature trip

functions, rather, the isolation is dependent on the high flow or

low pressure trip functions where a delay in the response of the

temperature isolation instrumentation will have no adverse impact on

the consequences of the accidents described in the SAR.

An evaluation was performed to determine the potential impacts

due to the proposed changes affecting the room temperatures used in

the environmental qualification program. The results of this

evaluation determined that the postulated peak temperatures for the

HPCI pump room and the HPCI and RCIC piping areas would be at the

saturation temperature for the HPCI or RCIC break blow-down in these

compartments, therefore, these compartment temperatures values will

not be exceeded. The RCIC pump room and isolation valve compartment

environmental qualification temperatures were not postulated to be

at the saturation temperature. However, this does not increase the

consequences of any of the accident described in the SAR because the

equipment which is normally required for RCIC system operation and

which is located in the RCIC pump compartment is not required to

operate following breakage of the RCIC steam supply line. The only

equipment in the RCIC pump compartment that is required to operated

following a RCIC steam line break is the RCIC leak detection

instrumentation which are qualified to operate at temperatures

greater than the saturation temperature. Finally, the isolation

valve compartment postulated peak temperatures result from a HPCI

steam line break in the Unit 1 and 2 isolation valve compartments.

This line break produces the highest isolation valve compartment

temperatures which bounds the results of a RCIC steam line break in

the isolation valve compartment and the HPCI and RCIC steam lien

breaks in the HPCI and RCIC pump rooms and piping areas. However,

since the leak detection and isolation actuation trip set-points for

the instruments in the isolation valve compartment are not being

changed, then the environmental conditions in the isolation valve

compartment will remain unchanged. This will assure that the

isolation valves will be able to provide isolation when required.

For HPCI or RCIC leaks, the environmental conditions were not

the only design basis considerations evaluated. The radiological

affects were also considered. By increasing the upper allowable high

ambient temperature or high delta temperature values for certain

line break sizes there will be a larger total mass blow-down from

the break due to the corresponding lengthening of the time to reach

the higher temperature limit. However, the total integrated mass of

blowdown prior to isolation of the HPCI or RCIC steam line break

will still be bounded by the LGS UFSAR accident analysis and

therefore, the radiological consequences of these breaks as

described in the SAR will remain unchanged. These conclusions are

supported by an evaluation that provided the design basis for the

main steam line break and then examines the radiological

consequences at the upper and lower end of the HPCI and RCIC break

spectrum. Since the largest HPCI and RCIC breaks are isolated based

on high flow and not based on compartment temperature increases,

then the proposed changes in the temperature set-points have no

impact on the radiological consequences of the design basis HPCI or

RCIC pipe break accidents as described in the SAR.

The impact of the proposed changes on the probability of a

malfunction of the system isolation instrumentation, valves, or the

HPCI or RCIC systems was evaluated. The isolation actuation

instruments are qualified for the expected environmental conditions

and the proposed set-points are within the normal operating range of

the instruments. Therefore, these isolation actuation instruments

are more likely to randomly fail than before. In addition, by

ensuring that there is no adverse impact on the ability of the HPCI

or RCIC systems to respond to events which are caused by

malfunctions of equipment, then the consequences of these events are

not increased. An adequate margin between the proposed lower

allowable trip values and the postulated equipment room

environmental conditions is being maintained such that an

inadvertent actuation of the HPCI or RCIC system isolation function

is also no more likely to occur. The increase in the temperature

isolation allowable trip values will allow increased blow-down from

a pipe break or crack which will result in higher pump compartment

temperatures and pressures than before for a given break size;

however, the overall impact is still bounded by the LGS UFSAR

Section 3.6 ruptured piping analyses. The isolation actuation

instruments are qualified for the expected environmental conditions,

and the proposed set-points are also within the normal operating

range of the isolation instruments. Therefore, the instruments are

no more likely to randomly fail and cause the loss of the HPCI or

RCIC system than before. In fact, by increasing the qualification

limits of the HPCI and RCIC systems, the systems will be able to

remain operable with an even large steam leak in the room when room

cooling is available. Therefore, the changes will have no impact on

the operating plant that would increase the possibility or

consequences of a malfunction of equipment important to safety.

Since the proposed changes will maintain the HPCI or RCIC steam

isolation system design basis, where the consequences are bounded by

an analysis contained in the LGS UFSAR, and will only change the

set-points of the existing instrumentation without impacting

equipment important to safety, the proposed Technical Specifications

changes do not involve a significant increase in the probability or

consequences of an accident previously evaluated.

2. The proposed TS changes do not create the possibility of a

new or different kind of accident from any accident previously

evaluated.

The proposed TS changes will not create the possibility of a

different type of accident or malfunction of equipment since the

changes will only increase the trip set-points of the

instrumentation which detect increases in the temperature in the

HPCI and RCIC equipment rooms. The physical establishment and

resetting of the set-points of these accident detection and

mitigation instruments will have not direct physical impact on the

plant's normal operating conditions and will not create any new

accident initiators or failure modes. The severity of the potential

piping system pressure transients caused by the isolation of the

HPCI or RCIC steam lines at higher room temperatures remains

unchanged since the isolation occurs after the postulated break

blow-down has dropped to its steady state rate. Therefore, the

changes will not result in a pipe break or result in any malfunction

of equipment that has not previously been postulated to occur.

Therefore, the proposed set-points will not create the

possibility of a different type of accident or possibility of a

different type of malfunction of equipment important to safety than

previously evaluated in the SAR.

3. The proposed TS changes do not involve a significant

reduction in a margin of safety.

The margin of safety for the isolation actuation instrumentation

as defined in the TS bases is not reduced. The proposed system

isolation TS trip set-points were selected to provide equivalent

margins that ensure the effectiveness of the isolation systems to

mitigate the consequences of accidents without compromising the

operability of the HPCI and RCIC systems. The proposed trip set-

points and proposed allowable value ranges maintain adequate margins

between these new values and the operating range of the HPCI and

RCIC systems in order to prevent the inadvertent actuation of the

isolation system and the loss of either the HPCI or RCIC systems.

The differences between the trip set-points and the allowable values

are being maintained as an allowance for instrument drift. The trip

set-points and the allowable ranges are within the specified range

of the instruments and therefore, the accuracy and drift will

provide the same margin of safety as previously assumed.

Therefore, the proposed TS change do 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 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: Pottstown Public Library, 500 High

Street, Pottstown, Pennsylvania 19464.

Attorney for licensee: J. W. Durham, Sr., Esquire, Sr. V. P. and

General Counsel, Philadelphia Electric Company, 2301 Market Street,

Philadelphia, Pennsylvania 19101

NRC Project Director: Mohan C. Thadani, Acting

Philadelphia Electric Company, Docket Nos. 50-352 and 50-353,

Limerick Generating Station, Units 1 and 2, Montgomery County,

Pennsylvania

Date of amendment request: July 22, 1994

Description of amendment request: This amendment would remove the

surveillance frequency details which govern 10 CFR 50, Appendix J, Type

B and C testing from Technical Specifications.

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. The proposed Technical Specifications changes do not involve

a significant increase in the probability or consequences of an

accident previously evaluated.

The proposed changes involve the removal of repetitious

surveillance details from TS also found in 10 CFR 50, Appendix J,

and rewording of TS. The removal and rewording involves no technical

changes to the existing TS. The changes to the existing TS are

proposed in order to be consistent with NUREG-1433. During the

development of NUREG-1433, certain wording preferences or English

language conventions were adopted. The proposed changes to this TS

section are administrative in nature and do not impact initiators of

analyzed events. They also do not impact the assumed mitigation of

accidents or transient events. Therefore, the changes do not involve

a significant increase in the probability or consequences of an

accident previously evaluated.

2. The proposed TS changes do not create the possibility of a

new or different kind of accident from any accident previously

evaluated.

The proposed changes do not involve a physical alteration of the

plant or changes in methods governing normal plant operation. The

proposed changes will not impose any new or different requirements

or eliminate any existing requirements. Therefore, the changes do

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

from any accident previously evaluated.

3. The proposed TS changes do not involve a significant

reduction in a margin of safety.

The changes are administrative in nature and will not involve

any technical changes. The proposed changes will not reduce a margin

of safety because they have no impact on any safety analysis

assumptions. In addition, because the changes are administrative in

nature, no question of safety is involved. Therefore, the changes do

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 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: Pottstown Public Library, 500 High

Street, Pottstown, Pennsylvania 19464.

Attorney for licensee: J. W. Durham, Sr., Esquire, Sr. V. P. and

General Counsel, Philadelphia Electric Company, 2301 Market Street,

Philadelphia, Pennsylvania 19101

NRC Project Director: Mohan C. Thadani, Acting

Public Service Electric & Gas Company, Docket Nos. 50-272 and 50-

311, Salem Nuclear Generating Station, Unit Nos. 1 and 2, Salem

County, New Jersey

Date of amendment request: August 19, 1994

Description of amendment request: This change would reduce the

minimum setpoints and allowable values for the Steam Generator Level -

Low-Low and Low reactor protection system signals. The bases would also

be modified to expand the description of the relationship between

setpoints, allowable values and the plant safety analysis.

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. do not involve a significant increase in the probability or

consequences of an accident previously evaluated.

The Steam Generator Water Level--Low-Low signal and the Low

Steam Generator Level coincident with Steam Flow/Feed Flow Mismatch

signal are designed to mitigate design basis transients involving

significant reductions of steam generator inventory (e.g., Loss of

Normal Feedwater, Turbine Trip, Loss of Offsite Power, Feedwater

Line Break). The setpoints and allowable values for these protection

signals are prescribed by Technical Specifications such that

performance of the signals is consistent with the plant safety

analyses, considering the effects of channel uncertainties. The

proposed reductions to the setpoints and allowable values for the

low-low and low steam generator level signals would not affect the

probability of any transient that the protection signals are

designed to mitigate. The changes would reduce the probability of

unnecessary reactor trips and Auxiliary Feedwater (AFW) system

actuations by providing greater operating margin for plant

evolutions involving steam generator level changes (e.g., plant

startup). Therefore, the proposed changes do not involve any

increase in probability of an accident previously evaluated.

The changes to the Steam Generator Water Level--Low-Low signal

would not result in any increase in consequences of a previously

analyzed accident because the proposed setpoint and allowable value

would continue to ensure the safety analysis assumptions remain

valid. As described in the accompanying changes to the Technical

Specifications Bases, the channel uncertainty calculations performed

to establish the relationships between the setpoints, allowable

values and safety analyses are consistent with NRC Regulatory Guide

1.105, Revision 2. Low Steam Generator Level coincident with Steam

Flow/Feed Flow Mismatch signal is not credited in the UFSAR Chapter

15 safety analyses. The proposed changes to the low steam generator

level setpoint and allowable value would continue to provide

reliable backup to the low-low level trip signal, consistent with

IEEE-279-1971. Therefore, the proposed changes would not involve an

increase in consequences of any previously analyzed accident.

2) do not create the possibility of a new or different kind of

accident from any accident previously evaluated.

The proposed changes would continue to ensure the appropriate

reactor protection system functions (reactor trip and AFW

initiation) are initiated in the event that steam generator water

level decreases to the value used in the plant safety analyses. The

proposed changes would not involve any changes in protection system

logic or function, and do not involve any plant configurations that

could adversely affect the initiation or progression of any accident

sequence. Therefore, the proposed changes do not create the

possibility of a new or different kind of accident from any accident

previously evaluated.

3) do not involve a significant reduction in a margin of safety.

The proposed setpoints and allowable values would continue to

ensure that the assumptions in the safety analyses remain valid,

with appropriate consideration of protection system channel

uncertainties. Therefore, the proposed changes do not involve a

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 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: Salem Free Public library, 112 West

Broadway, Salem, New Jersey 08079

Attorney for licensee: Mark J. Wetterhahn, Esquire, Winston and

Strawn, 1400 L Street, NW, Washington, DC 20005-3502

NRC Project Director: Mohan C. Thadani, Acting

South Carolina Electric & Gas Company, South Carolina Public

Service Authority, Docket No. 50-395, Virgil C. Summer Nuclear

Station, Unit No. 1, Fairfield County, South Carolina

Date of amendment request: July 20, 1994

Description of amendment request: The proposed change would modify

the Virgil C. Summer Nuclear Station (VCSNS) Technical Specification

(TS) Tables 2.2-1, ``Reactor Trip System Instrumentation Setpoints,''

and 3.3-4, ``Engineered Safety Features Actuation System

Instrumentation Trip Setpoints,'' and several associated bases. The

proposed change would remove three columns from the Tables. The columns

contain specific rack and sensor allowable drift values.

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. Operation of VCSNS in accordance with the proposed license

amendment does not involve a significant increase in the probability

or consequences of an accident previously evaluated.

This change does not alter or delete any setpoints or Allowable

Values, and as such, has no affect on any assumptions used for

accident analysis. No hardware or software changes are involved, so

no common mode or common cause failures can occur as a result of

this change. This change has no impact on the daily operation of

VCSNS. The performance of periodic calibrations and channel checks

will assure the setpoints remain within tolerance. Since this

amendment request affects only information that is no longer used in

the daily operation of the plant and has no impact on accident

analysis, the probability or consequences of an accident previously

evaluated are not increased.

2. The proposed license amendment does not create the

possibility of a new or different kind of accident from any accident

previously evaluated.

This change revises two TS tables which contain both setpoints

and Allowable Values as well as other information for safety trip

functions. However, the revision only deletes three columns of data

that were used in determining the operability of one channel of the

safety function. These values are also used in determining the

setpoints and are based on measured or published tolerances and

uncertainties. Although these columns are being deleted, no changes

to any hardware, software, or setpoints will occur. Since these

changes do not have any plant impact, no new failure mechanisms are

introduced. Only the information not used on a daily basis is being

removed from these tables; this will not create the possibility of a

new or different kind of accident from any accident previously

evaluated.

3. The proposed license amendment does not involve a significant

reduction in a margin of safety.

This change revises the format of TS Tables 2.2-1 and 3.3-4

which list the setpoint and Allowable Values for safety trip

functions. The data that is being removed from these tables was used

to establish clear reportability requirements for any portion of one

channel of any of the listed safety trip functions. Since the

reporting requirements have changed and an LER is not required if

one coincident channel is inoperable, this data is no longer used in

daily operations. The margin of safety was established when

setpoints and Allowable Values were determined, and no changes to

these values are involved. There is no reduction in a margin of

safety that could affect the plant, SCE&G employees, or the public.

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: Fairfield County Library, Garden and

Washington Streets, Winnsboro, South Carolina 29180

Attorney for licensee: Randolph R. Mahan, South Carolina Electric &

Gas Company, Post Office Box 764, Columbia, South Carolina 29218

NRC Project Director: David B. Matthews

South Carolina Electric & Gas Company, South Carolina Public

Service Authority, Docket No. 50-395, Virgil C. Summer Nuclear

Station, Unit No. 1, Fairfield County, South Carolina

Date of amendment request: July 20, 1994

Description of amendment request: The proposed change would modify

the Virgil C. Summer Nuclear Station, Unit 1, (VCSNS) Technical

Specifications (TS) to allow alternative, equivalent testing of diesel

fuel used in the emergency diesel generators (EDG). These alternative

methods are necessary due to recent changes in Environmental Protection

Agency (EPA) regulations that are designed to limit the use of high

sulfur fuels.

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. The probability or consequences of an accident previously

evaluated is not significantly increased.

The change in testing methods for the EDG fuel oil has no impact

on the probability or consequences of any design basis accident.

These tests have been determined to be equivalent to the previously

approved testing methods and are needed due to changes in the EPA's

regulations regarding sulfur in motor vehicle fuels. The dye used to

identify high sulfur fuels will have no adverse affect on the

performance of the EDG's. The proposed testing assures a continued

high level of quality of the diesel fuel received and stored on

site.

The change in revision level of a reference in TS section

6.9.1.11 has no impact on the probability of occurrence or

consequences of any design basis accident. All design and

performance criteria will continue to be met and no new single

failure mechanisms will be created. The change in revision level for

WCAP-10216-P-A does not involve any alterations to plant equipment

or procedures which could affect any operational modes or accident

precursors. This change only incorporates by reference, the

methodology for determining the penalty to be used in calculating

Core Operating Limits. This methodology allows the penalty to be

cycle specific and is primarily affected by the core configuration.

This penalty is used for normal operation and provides more

conservatism to the core operation for the cycle.

2. [The proposed license amendment does not] create the

possibility of a new or different kind of accident from any accident

previously evaluated.

The change in testing methods for the EDG fuel oil will not

create the possibility of a new or different kind of accident from

any accident previously evaluated. These tests have been determined

by the EPA and other organizations to be equivalent to the

previously approved testing methods. The effect of the blue dye,

used to identify high sulfur fuels, on the performance of the EDGs

has been evaluated and determined to be insignificant. The testing

proposed assures a continued high level of quality for the diesel

fuel received and stored on site.

The change of revision level of a reference in TS section

6.9.1.11 has no impact on the probability of occurrence or

consequences of any design basis accident. All design and

performance criteria will continue to be met and no new single

failure mechanisms will be created. The change in revision level for

WCAP-10216-P-A does not involve any alterations to plant equipment

or procedures which could affect any operational modes or accident

precursors. This change only incorporates, by reference, the

methodology for determining the penalty to be used in calculating

Core Operating Limits. This methodology allows the penalty to be

cycle specific and is primarily affected by the core configuration.

This penalty is used for normal operation and provides more

conservatism to the core operation for the cycle.

3. [The proposed license amendment does not] involve a

significant reduction in a margin of safety.

The change in testing methods for the EDG fuel oil will not

involve a significant reduction in a margin of safety. The proposed

testing methods have been determined to be equivalent to the

previously approved testing methods

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