Applications and Amendments to Facility Operating Licenses Involving No Significant Hazards Considerations; Biweekly Notice

NUCLEAR REGULATORY COMMISSION

Applications and Amendments to Facility Operating Licenses

Involving No Significant Hazards Considerations; Biweekly Notice

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 June 10, 1995, through June 22, 1995. The

last biweekly notice was published on June 21, 1995 (60 FR 32359).

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.

[[Page 35059]]

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.

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

intervene is discussed below.

By August 4, 1995, 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 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, 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

[[Page 35060]]

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, and at the local public document room for

the particular facility involved.

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

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

1, 2, and 3, Maricopa County, Arizona

Date of amendment requests: May 2, 1995.

Description of amendment requests: The proposed amendment would

remove from the technical specifications (TS) plant elevations for the

minimum water volume required in the spent fuel pool (SFP) and relocate

them to site procedures. This proposed TS amendment also includes two

changes to correct administrative errors in the TS.

Basis for proposed no significant hazards consideration

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

provided its analysis about the issue of no significant hazards

consideration, which is presented below:

1. The proposed change does not involve a significant increase

in the probability or consequences of an accident previously

evaluated.

The proposed change eliminates the plant elevations from TS

Figure 3.1-1, ``Minimum Borated Water Volumes'' for the SFP. The

change is administrative in nature and does not involve any

modifications to plant equipment or affected plant operation. The

required volume of water in the SFP is identified on the figure and

will remain unchanged by this amendment. This request relocates the

plant elevations to site procedures where they will be controlled in

accordance with the provisions of 10 CFR 50.59.

The removal of the reference to Table 3.8-2 in the Unit 3 TS

3.8.4.1 and adding the word ``containment'' to the Unit [2] TS

4.6.3.1 are administrative change[s] and do not involve any

modifications to plant equipment or affect plant operation. These

administrative changes do not affect the scope or intent of any test

within the TS.

Therefore, the proposed changes do not involve a significant

increase in the probability or consequences of an accident

previously evaluated.

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

or different kind of accident from any accident previously

evaluated.

The proposed change eliminates the plant elevations from TS

Figure 3.1-1, ``Minimum Borated Water Volumes'' for the SFP. The

change is administrative in nature and does not involve any

modifications to plant equipment or affect plant operation. The

removal of plant elevations from the figure does not cause any

change in the method by which any safety-related system performs its

function. The required volume of water in the SFP is identified on

the figure and will remain unchanged by this amendment.

The removal of the reference to Table 3.8-2 in the Unit 3 TS

3.8.4.1 and adding the word ``containment'' to the Unit 2 TS 4.6.3.1

are administrative changes and do not involve any modifications to

plant equipment or affect plant operation. These administrative

changes do not affect the scope or intent of any test within the TS.

Therefore, the proposed changes do not create the possibility of

a new or different kind of accident from any accident previously

evaluated.

3. The proposed change does not involve a significant reduction

in a margin of safety.

The proposed change eliminates the plant elevations from TS

Figure 3.1-1, ``Minimum Borated Water Volumes'' for the SFP. The

change is administrative in nature and does not involve any

modifications to plant equipment or affect plant operation. The

required volume of water in the SFP is identified on the figure and

will remain unchanged by this amendment.

The removal of the reference to Table 3.8-2 in the Unit 3 TS

3.8.4.1 and adding the word ``containment'' to the Unit 2 TS 4.6.3.1

are administrative changes and do not involve any modifications to

plant equipment or affect plant operation. These administrative

changes do not affect the scope or intent of any test within the TS.

Therefore, based upon the above, 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

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

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

amendment requests involve no significant hazards consideration.

Local Public Document Room location: Phoenix Public Library, 12

East McDowell Road, Phoenix, Arizona 85004.

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

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

Station 9068, Phoenix, Arizona 85072-3999.

NRC Project Director: William H. Bateman.

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

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

Maryland

Date of amendments request: June 2, 1995.

Description of amendments request: The proposed amendments would

revise the pressurizer safety valve setpoint tolerance ``as-found''

acceptance criterion to +2%/-1% for the valve with the lower setpoint

(RC-200) and plus or minus 2% for the valve with the upper setpoint

(RC-201). The ``as-left'' setpoint tolerance will remain plus or minus

1% for both valves.

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 pressurizer safety valves are used to prevent exceeding the

Reactor Coolant System (RCS) pressure safety limit. The proposed

change to increase the pressurizer safety valve setpoint tolerance

for the ``as-found'' acceptance criteria from [plus or minus]1% to

+2%/-1% for the valve with the lower pressure setpoint, and [plus or

minus] 2% for the valve with the upper pressure setpoint, does not

affect any initiating event. The proposed change does not affect the

consequences of the previously evaluated design basis accidents as

the new safety valve setpoint tolerances are bounded by the

assumptions in the safety analysis. 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 to increase the ``as-found'' setpoint

tolerances does not involve any changes in equipment or the function

of these safety valves. The proposed change does not represent a

change in the configuration or operation of the plant. The test

method for the pressurizer safety valves will remain the same. The

increase in the setpoint tolerances does not create any new accident

initiator. Therefore, the proposed change does not create the

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

previously evaluated.

[[Page 35061]]

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

safety.

The pressure safety limit for the RCS protects the structural

integrity of the system from failure due to overpressurization. The

pressurizer safety valves are used to prevent the RCS pressure from

exceeding the safety limit. The proposed change to the pressurizer

safety valve setpoint tolerances will continue to prevent the RCS

pressure from exceeding the design safety limit during any design

basis event. Therefore, the proposed change does not involve a

significant reduction in a margin of safety.

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

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

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

amendments request involves no significant hazards consideration.

Local Public Document Room location: Calvert County Library, Prince

Frederick, Maryland 20678.

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

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

NRC Project Director: Ledyard B. Marsh.

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

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

Maryland

Date of amendments request: June 6, 1995.

Description of amendments request: The proposed amendments would

revise the Calvert Cliffs Nuclear Plant Units 1 and 2 Technical

Specifications, extending certain 18-month frequency surveillances to a

refueling interval (nominally 24 months, not to exceed 30 months).

Systems and equipment affected are the Reactor Protective System (RPS),

Engineered Safety Features Actuation System (ESFAS), Power-Operated

Relief Valve (PORV) actuation instruments, Low Temperature Overpressure

Protection (LTOP)-related instruments, Remote Shutdown Panel

instruments, Post-Accident Monitoring (PAM) instruments, Containment

Sump Level instruments, and Radiation Monitoring instruments.

This amendment request would extend the nominal surveillance

interval requirement from 18 months to a refueling interval (nominally

24 months, not to exceed 30 months) for instrument channel

calibrations, RPS and ESFAS total bypass function operability

verification, RPS and ESFAS time response tests, ESFAS Manual Trip

Button channel functional tests, and ESFAS Automatic Actuation Logic

Channel Functional Tests. Calvert Cliffs has been operating on a 24-

month fuel cycle since July 1987 (Unit 2) and July 1988 (Unit 1),

performing some Technical Specification surveillances, such as the ones

described here, during mid-cycle outages. The request is the last of a

series of proposed license amendments that would eliminate the need for

planned mid-cycle outages to perform required surveillances.

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 proposed change would extend surveillance intervals for

Reactor Protective System (RPS), Engineered Safety Features

Actuation System (ESFAS), Power-Operated Relief Valve (PORV), Low

Temperature Overpressure Protection (LTOP), Remote Shutdown, Post-

Accident Monitoring (PAM), Radiation Monitoring, and Containment

Sump Level Instruments.

The purpose of the RPS is to effect a rapid reactor shutdown if

any one or a combination of conditions deviates from a pre-selected

operating range. The system functions to protect the core and the

Reactor Coolant System pressure boundary. The purpose of the ESFAS

is to actuate equipment which protects the public and plant

personnel from the accidental release of radioactive fission

products if an accident occurs, including a loss-of-coolant

incident, main steam line break, or loss of feedwater incident. The

safety features function to localize, control mitigate, and

terminate such incidents in order to minimize radiation exposure to

the general public. The Post-Accident Monitoring instruments provide

the Control Room operators with primary information necessary to

take manual actions, as necessary, in response to design basis

events, and to verify proper system response to plant conditions and

operator actions. The purpose of the Remote Shutdown System is to

provide plant parameter indications to operators on a Remote

Shutdown Panel to be used while placing and maintaining the plant in

a safe shutdown condition in the event the Control Room is

uninhabitable. The indications are used to verify proper system

response to plant conditions and operator actions. The LTOP System

protects against Reactor Coolant System overpressurization at low

temperatures by a combination of administrative controls and

hardware. The hardware includes two Power-Operated Relief Valves

with variable pressurizer pressure setpoints when operating in the

LTOP operating parameter region. The Containment Sump High Level

Alarm System provides an alarm in the Control Room for a containment

sump to provide one of the available indications of excessive RCS

leakage during normal plant operation. The Containment Area High

Range Radiation Monitoring System provides an indication of high

radiation levels in containment. The Containment Purge System

actuates equipment to prevent the release of radioactive material to

the environment in the event of a reactor coolant leak, a shielding

failure, or a fuel pin failure when the reactor vessel head is

removed.

The instruments in each of the systems described above are

designed to be used in response to an accident. Failure of any of

these systems is not an initiator for any previously evaluated

accident. Therefore, the proposed change would not involve an

increase in the probability of an accident previously evaluated.

Many of the instruments addressed in this license amendment

request will have or have recently had a new brand of sensor

installed. The effect of the increased surveillance interval with

the new sensors was analyzed. The new sensors do not effect the

physical design description of the plant, any design or functional

requirements, or surveillances. The proposed Technical Specification

change extending the surveillance interval from 18 months to a

refueling interval (nominally 24 months, not to exceed 30 months)

does not physically change the plant, change any design or

functional requirements, or effect the surveillances themselves.

Analysis has shown that no trip setpoints need to be changed, and

operator indications will continue to be accurate for control of

plant parameters to effect a safe shutdown. The equipment will

continue to perform as designed to mitigate the consequences of

accidents. Therefore, the proposed change would not involve a

significant increase in the consequences of an accident. [* * *]

Therefore, the proposed change would 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 to increase the interval RPS, ESFAS, PORV,

LTOP, Remote Shutdown, PAM, Radiation Monitoring, and Containment

Sump Level instrument surveillances from 18 months to a refueling

interval (nominally 24 months, not to exceed 30 months) does not

involve a significant change in the design or operation of the

plant. No hardware is being added to the plant as part of the

proposed change. Some detector upgrades in specific plant systems to

enhance the performance of those systems have been or will be

performed. However, those upgrades were evaluated and deemed

acceptable under 10 CFR 50.59 and are not part of this request. The

Reactor Protective System, Engineered Safety Features Actuation

System, Power-Operated Relief Valve, Low Temperature Overpressure

Protection, Containment Sump Level, one Radiation Monitoring

actuation setpoints will not be changed. Analysis has shown that the

remote shutdown and PAM indications will continue to be accurate.

The proposed change will not introduce any new accident initiators.

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

different type of accident from any previously evaluated.

3. Does operation of the facility in accordance with the

proposed amendment

[[Page 35062]]

involve a significant reduction in a margin of safety?

The impact of the surveillance interval extension request was

evaluated for each Technical Specification-related safety function

for each of the RPS, ESFAS, PORV, LTOP, Remote Shutdown, PAM,

Radiation Monitoring, and Containment Sump Level instruments

addressed by this submittal. In all cases, parameters specified in

the related accident analysis were determined to be unaffected by

the surveillance interval extension, and no accident analyses limits

required changes. The Reactor Protective System, Engineered Safety

Features Actuation System, Power-Operated Relief Valve, Low

Temperature Overpressure Protection, Containment Sump Level, and

Radiation Monitoring actuation setpoints will not be changed.

Analysis has shown that the remote shutdown and PAM indications will

continue to be accurate. The methods for detection of degraded

instrument operation have not been changed, and remote shutdown and

PAM operator indications will continue to provide adequate accuracy.

The methods for detection of degraded instrument operation have not

been changed, and remote shutdown and PAM operator indications will

continue to provide adequate accuracy.

The proposed change does not affect the operation of the systems

involved. The surveillance interval extension will not affect the

design of the systems, and methods for detection of degraded

instrument operation will continue to identify operation problems

between calibrations. Therefore, the proposed change does not

involve a significant reduction in a margin of safety.

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

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

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

amendments request involves no significant hazards consideration.

Local Public Document Room location: Calvert County Library, Prince

Frederick, Maryland 20678.

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

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

NRC Project Director: Ledyard B. Marsh.

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

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

Maryland

Date of amendments request: June 9, 1995.

Description of amendments request: The proposed amendments revise

the Calvert Cliffs Nuclear Power Plant Radiological Effluent Technical

Specifications (RETS) consistent with Generic Letter (GL),

``Implementation of Programmatic Controls For Radiological Effluent

Technical Specifications in the Administrative Controls Section of the

Technical Specifications and the Relocation of Procedural Details of

RETS to the Offsite Dose Calculation Manual or the Process Control

Program (Generic Letter 89-01),'' dated January 31, 1989, and the

Improved Standard Technical Specifications for Combustion Engineering

Plants published in NUREG-1432, as modified by Mr. W. T. Russell's

letter of October 25, 1993, ``Content of Standard Technical

Specifications,'' to the Improved Technical Specification Owners Group

Chairpersons. Changes for relocating the procedural details of the

current RETS to the Offsite Dose Control Manual (ODCM) has been

prepared in accordance with the proposed changes to the Administrative

Controls section of the 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:

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 proposed changes will provide human factor improvements for

the Technical Specifications by relocating existing procedural

details of the current Radiological Effluent Technical

Specifications to the Offsite Dose Control Manual (ODCM). Procedural

details for solid radioactive wastes will be relocated to the

Process Control Program. The proposed amendment (1) incorporates

programmatic controls in the Administrative Controls section of the

Technical Specifications that satisfy the requirements of 10 CFR

20.1302, 40 CFR Part 190, 10 CFR 50.36a, 10 CFR Part 50, Appendix I,

and our current Technical Specifications; (2) relocates the existing

procedural details in current specifications involving radioactive

effluent monitoring instrumentation, the control of liquid and

gaseous effluents, equipment requirements for liquid and gaseous

effluents, radiological environmental monitoring, and radiological

reporting details from the Technical Specifications to the ODCM; (3)

simplifies the associated reporting requirements; (4) simplifies the

administrative controls for changes to the ODCM; and (5) updates the

definitions of the ODCM consistent with these changes.

Relocating existing requirements and eliminating requirements

which duplicate regulatory requirements provide Technical

Specifications which are easier to use. Because existing

requirements are relocated to established programs where changes to

those programs are controlled by regulatory requirements, there is

no reduction in commitment and adequate control is still maintained.

Likewise, the elimination of requirements which duplicate regulatory

requirements enhances the usability of the Technical Specifications

without reducing commitments. The additional improvements being

proposed neither add nor delete requirements, but merely clarify and

improve the readability and understanding of the Technical

Specifications. Since the requirements remain the same, these

changes only affect the method of presentation, and as such, would

not affect possible initiating events for accidents previously

evaluated or any system functional requirement.

Furthermore, no safety-related equipment, safety function, or

plant operation will be altered as a result of this proposed change.

The changes are unrelated to the initiation and mitigation of

accidents and equipment malfunctions addressed in the Updated Final

Safety Analysis Report.

Therefore, the proposed changes do 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.

Transferring the procedural details of radiological effluent

monitoring and reporting from the Technical Specifications to the

ODCM has no impact on plant operation or safety. No safety-related

equipment, safety function, or plant operation will be altered as a

result of this proposed change. No changes to plant components or

structures are introduced which could create new accidents or

malfunctions not previously evaluated.

Therefore, the proposed changes do not create the possibility of

a new or different kind of accident from any accident previously

evaluated.

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

safety.

The margin of safety associated with the affected Technical

Specifications is to provide assurance that the releases of

radioactive materials during actual or potential releases of liquid

or gaseous effluents do not exceed the limits of 10 CFR Part 20.

This license amendment request relocates the methodology and

parameters used to ensure that the 10 CFR Part 20 limits are

maintained, but does not change any of these requirements. Thus, no

methodology and parameters for controlling radioactive effluent

releases will be changed.

The procedural details of the current Radiological Effluent

Technical Specifications will be transferred to the ODCM and

replaced with programmatic controls consistent with regulatory

requirements, including controls on revisions to the ODCM. Thus, no

requirements or controls will be reduced.

The proposed revisions to the reporting requirements for

Radiological Effluent Release Report and the revision from the old

10 CFR 20.106 requirements to the new 10 CFR 20.1302 have no impact

on plant systems, plant operations or accident precursors. The

changes to the effluent

[[Page 35063]]

reporting requirements and the updated reference to 10 CFR 20.1302 do

not change either the means of controlling radioactive releases or

the effluent release limits. Therefore, there will be no change in

the types and amounts of effluents that will be released, nor will

there be an increase in individual or cumulative radiation exposures

to any member of the public.

Therefore, the proposed 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 50.92(c) are

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

amendments request involves no significant hazards consideration.

Local Public Document Room location: Calvert County Library, Prince

Frederick, Maryland 20678.

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

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

NRC Project Director: Ledyard B. Marsh.

Carolina Power & Light Company, Docket No. 50-261, H.B. Robinson Steam

Electric Plant, Unit No. 2, Darlington County, South Carolina

Date of amendment request: June 3, 1995.

Description of amendment request: The requested Technical

Specification (TS) change clarifies the definition of operability of

the charging pumps by adding a footnote to TS Section 3.2.2.a that

states that the connectibility of the emergency power sources is not

required for charging pump operability.

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:

This change request does not involve a significant hazards

consideration for the following reasons.

1. The requested change does not involve a significant increase

in the probability or consequences of an accident previously

evaluated. The requested change clarifies that the emergency power

sources are not required for the operability of the charging pumps.

Operation of the charging pumps is not considered in the assumptions

for initiation of any analyzed accident and is not credited for

accident mitigation in any analyzed accidents in the safety analysis

report. Therefore, the availability of emergency power sources to

the charging pumps does not affect the probability of occurrence or

consequences of an analyzed accident in the safety analysis report.

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

or different kind of accident from any accident previously

evaluated. The requested change clarifies that the emergency power

sources are not required for the operability of the charging pumps.

The design requirements of the charging pumps to provide reactor

coolant inventory and boron inventory control are not changed. The

operability of the emergency power source to the charging pumps is

not a precursor to any accident scenario. Failure of the charging

pumps is bounded by the plant design which strips the charging pumps

from the emergency buses under certain conditions. Since the change

does not involve changes in the operation of the plant, or physical

or equipment changes or involve controls for accident mitigation

equipment, the requested change will not create the possibility of

new or different kind of accident from any accident previously

evaluated.

3. The requested change clarifies that the emergency power

sources are not required for the operability of the charging pumps.

Since the charging pumps are stripped from the emergency buses in

the event of a loss of power and safety injection, emergency power

sources to the charging pumps are not guaranteed to mitigate the

consequences of an analyzed accident. As a result, no credit is

taken for the charging function in analyzed accidents and the margin

of safety as described in the safety analysis report is unchanged.

Therefore, the requested 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 10 CFR 50.92(c) are

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Hartsville Memorial Library,

147 West College Avenue, Hartsville, South Carolina 29550.

Attorney for licensee: R. E. Jones, General Counsel, Carolina Power

& Light Company, Post Office Box 1551, Raleigh, North Carolina 27602.

NRC Project Director: David B. Matthews.

Commonwealth Edison Company, Docket Nos. 50-454 and 50-455, Byron

Station, Unit Nos. 1 and 2, Ogle County, Illinois

Docket Nos. 50-456 and 50-457, Braidwood Station, Unit Nos. 1 and 2,

Will County, Illinois

Date of amendment request: February 21, 1995.

Description of amendment request: The proposed amendments would

revise Byron and Braidwood technical specifications associated with the

reactor coolant system (RCS) resistance temperature detectors (RTDs)

used to obtain hot and cold leg temperatures. The amendments are

required because of proposed modification that will remove the existing

RTDs and their associated piping and valves and replace them with dual

element fast response RTDs mounted in the thermowells welded directly

in the RCS loop piping.

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 change does not involve a significant increase

in the probability or consequences of an accident previously

evaluated.

The proposed modification replaces the existing bypass piping

system with thermowell-mounted RTDs. Because the hot leg RTDs are

mounted directly in the scoops, temperature measurement inaccuracies

caused by imbalances in the flow scoop sample flow are eliminated.

The method of measuring coolant temperature with thermowell-mounted

fast response RTDs has been analyzed to be at least as effective as

the RTD bypass system. With the thermowells welded into the existing

RCS hot and cold leg nozzles and the elimination of the bypass

piping, the number of pressure boundary welds has been significantly

reduced, resulting in a reduced probability of a small break LOCA

[Loss of Coolant Accident].

The RTD response time is incorporated in the safety analyses. In

particular, RTD response time is modeled in the OT[DELTA]T [Over

Temperature Delta Temperature] and OP[DELTA]T [Over Pressure Delta

Temperature] trip functions. The overall response time modeled in

the safety analyses for the existing RTD bypass piping system is 8

seconds. The overall response time is the elapsed time from the time

the temperature change in the RCS exceeds the trip setpoint until

the rods are free to fall. More specifically, 6 seconds is modeled

as a first order lag term and 2 seconds as pure delay on the reactor

trip signal. The 6 second lag term includes such factors as: RTD

bypass piping fluid transport delay, RTD bypass piping thermal lag,

RTD response time, and RTD electronic filtering. The 2 second delay

on reactor trip addresses such factors as electronics delay, trip

breakers and gripper release.

Signal conditioning (filtering) of the individual loop [DELTA]T

and Tavg signals is represented by [time constants utilized in

the lag compensator for DELTA T] and [time constant utilized in the

measured Tavg lag compensator], respectively, in the OT[DELTA]T

and OP[DELTA]T equations in Technical Specification Table 2.2-1.

With the current bypass manifold system, the filter is not required

since the existing RTDs do not respond rapidly to local temperature

variances within the reactor coolant loop. The bypass piping and

manifold provide adequate mixing of the coolant, eliminating any

local temperature variances. Therefore, the values of [time

constants utilized in the lag compensator for DELTA T] and [time

[[Page 35064]]

constant utilized in the measured Tavg lag compensator] are

currently specified as 0 seconds, effectively turning off the

electronic filter. The new fast response RTDs may respond to

temperature spikes which are not representative of actual RCS bulk

fluid temperature. Signal conditioning may be required to eliminate

these temperature spikes. Although, the current Technical

Specifications do not provide for any signal conditioning, the 8

second total response time used in safety analyses has sufficient

margin to account for a typical 2 second time constant for signal

conditioning. Industry experience has shown that a 2 second filter

is adequate in eliminating the spikes.

The proposed fast response RTD/thermowell system also has an

overall response time of 8 seconds. However, the time distribution

for the parameters differ between the existing and proposed designs.

The existing design includes a transport time for RCS fluid to reach

the RTD, located in the manifold. The RTDs are directly immersed

into the coolant, providing a fast response. The new design no

longer has the transport delay. However, because the RTDs are

mounted in thermowells, the response time of the RTD/thermowell

combination will be increased over the existing system.

The effects of a redistribution of the time responses between

the total lag term (pipe transport delay, RTD response and

electronic filter delay) and electronics delay term have been

evaluated. Westinghouse completed a Safety Evaluation SECL-95-015,

``OT[DELTA]T and OP[DELTA]T Reactor Trip Response Time Safety

Evaluation'' to support the revision to the time requirements. The

evaluation concludes that, as long as the total response time

remains [less than or equal to] 8 seconds, the safety analyses

acceptance criteria continue to be met. The OT[DELTA]T and

OP[DELTA]T trip functions are unaffected by the change.

The following Updated Final Safety Analysis Report (UFSAR)

Chapter 15 events trip on OT[DELTA]T: Loss of Electric Load/Turbine

Trip, Uncontrolled RCCA Bank Withdrawal at Power, CVCS Malfunction

that Results in a Decrease in the Boron Concentration in the Reactor

Coolant, and Inadvertent Opening of a Pressurizer Safety or Relief

Valve. In addition, the following events trip on OP[DELTA]T:

Steamline Break at Hot Full Power for Core Response, and Steamline

Break Superheat Analysis. These events have been reviewed for a

change in the distribution of time responses for OT[DELTA]T and

OP[DELTA]T. The review concludes that the time response

redistribution did not result in a minimum DNBR lower than the

safety analyses limit, did not result in a fuel centerline melt, nor

did the superheated steam releases change from those currently

existing. Therefore, the radiological consequences for these events

do not increase as a result of the less restrictive time response

breakdown. Thus, the proposed amendment does not result in an

increase in the probability or consequences of a previously

evaluated accident.

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

or different kind of accident from any accident previously

evaluated.

The OT[DELTA]T and OP[DELTA]T trip functions are unaffected by

the change. Electronic filtering of the RTD signal has been

included, changing the dynamic compensation term of OT[DELTA]T and

OP[DELTA]T setpoint equations. No other changes to the setpoint

equation result from the proposed modification.

The added 7300 hardware is compatible with the existing 7300

electronic hardware now used. All changes to the 7300 protection

cabinets have been qualified. The proposed system is functionally

equivalent to the existing one. The proposed modification has been

reviewed for conformance with the Institute of Electrical and

Electronics Engineers (IEEE) 279-1971 criteria, associated General

Design Criteria, Regulatory Guides, and other applicable industry

standards. The single failure criterion is satisfied by the proposed

modification, since the independence of redundant protection sets is

maintained. The new RTD/thermowell system meets the equipment

seismic and environmental qualification requirements of IEEE

standards 344-1975 and 323-1974, respectively. The proposed changes

do not affect the protection system capabilities to initiate a

reactor trip. The 2 of 4 voting coincidence logic of the protection

sets is maintained. Therefore, the proposed modification meets all

appropriate IEEE criteria, industry standards and other guidelines.

In addition, the RTD outputs are used for rod control, turbine

runback, pressurizer level and other control systems. These control

systems receive the signal after it has been processed at the 7300

cabinets and are therefore unaffected by the proposed modification.

The design and installation of the thermowells is in accordance

with the American Society of Mechanical Engineers (ASME) Code

requirements. However, should a thermowell fail at the RCS pressure

boundary, the resulting accident is enveloped by current design

basis accident analyses. Thus, implementation of the proposed

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

of accident from any of those previously evaluated.

3. The proposed change does not involve a significant reduction

in a margin of safety.

The 7300 protection cabinets calculate individual loop [DELTA]T

and Tavg, based on the output of the RTDs. These values are

used in the OT[DELTA]T and OP[DELTA]T reactor protection trip

signals. Electronic filtering of the RTD signal will be included,

changing the dynamic compensation term of OT[DELTA]T and OP[DELTA]T

setpoint equations. No other changes to the setpoint equation result

from the proposed modification. Although the total response time

used as input into the safety analyses is unaffected by the proposed

modification, the distribution of response times between the total

lag (pipe transport delay, RTD response and electronic filter delay)

and the electronic delay has changed. The UFSAR events which rely on

OT[DELTA]T and OP[DELTA]T trips have been evaluated. The evaluation

concludes that the safety analyses acceptance criteria continue to

be met, since the total response time is consistent with the safety

analyses. The OT[DELTA]T and OP[DELTA]T trips function in the same

manner to terminate DNB-related transients. The reliability of the

reactor protection system is unaffected by this change. Thus, the

proposed modification does not involve a significant reduction in

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

requested amendments involve no significant hazards consideration.

Local Public Document Room location: For Byron, the Byron Public

Library District, 109 N. Franklin, P.O. Box 434, Byron, Illinois 61010;

for Braidwood, the Wilmington Public Library, 201 S. Kankakee Street,

Wilmington, Illinois 60481.

Attorney for licensee: Michael I. Miller, Esquire; Sidley and

Austin, One First National Plaza, Chicago, Illinois 60603.

NRC Project Director: Robert A. Capra.

Commonwealth Edison Company, Docket Nos. STN 50-454 and STN 50-455,

Byron Station, Unit Nos. 1 and 2, Ogle County, Illinois

Docket Nos. STN 50-456 and STN 50-457, Braidwood Station, Unit Nos. 1

and 2, Will County, Illinois

Date of amendment request: May 17, 1995.

Description of amendment request: The proposed amendment would

modify the technical specifications to allow steam generator tubes to

be repaired using the tungsten inert gas (TIG) welded sleeve process

developed by ABB Combustion Engineering (ABB/CE), remove the ability to

repair steam generator tubes using the Babcock & Wilcox Nuclear

Technologies (BWNT) kinetically welded sleeve process, and increase the

requirement to inspect the number of sleeved tubes from 3 percent of

the total number of sleeved tubes in all four steam generators (SGs) or

all sleeved tubes in one steam generator to 20 percent of each sleeve

design installed. The proposed amendments would also delete the

requirement to conduct additional corrosion testing to establish the

design life for the BWNT kinetically welded sleeve in the presence of a

crevice.

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 change does not involve a significant increase

in the probability or

[[Page 35065]]

consequences of an accident previously evaluated.

The proposed amendment allows the ABB/CE TIG welded tubesheet

sleeves and tube support plate sleeves to be used as an alternate

tube repair method for Byron and Braidwood Units 1 and 2 Steam

Generators (SGs). The sleeve configuration was designed and analyzed

in accordance with the criteria of Regulatory Guide (RG) 1.121 and

Section III of the ASME Code. Fatigue and stress analyses of the

sleeved tube assemblies produce acceptable results for both types of

sleeves as documented in ABB/CE Licensing Report CEN-621-P, Revision

00, ``Commonwealth Edison Byron and Braidwood Unit 1 & 2 Steam

Generator Tube Repair Using Leak Tight Sleeves, FINAL REPORT,''

April 1995. Mechanical testing has shown that the structural

strength of the sleeves under normal, faulted, and upset conditions

is within the acceptable limits specified in RG 1.121. Leakage rate

testing for the tube sleeves has demonstrated that primary to

secondary leakage is not expected during any plant condition. The

consequences of leakage through the sleeved region of the tube is

fully bounded by the existing steam generator tube rupture (SGTR)

analysis included in the Byron and Braidwood Updated Final Safety

Analysis Report (UFSAR).

The current Technical Specification 3.4.6.2.c primary to

secondary leakage limit of 150 gallons per day (gpd) through any one

SG ensures that SG tube integrity is maintained in the event of main

steam line break (MSLB) or loss of coolant accident (LOCA). The RG

1.121 criteria for establishing operational leakage rate limits

require a plant shutdown based upon a leak-before-break

consideration to detect a free span crack before a potential tube

rupture. The 150 gpd limit will continue to allow for early leakage

detection and require a plant shutdown in the event of the

occurrence of an unexpected crack resulting in leakage that exceeds

the TS limit.

The sleeves are designed to allow inservice inspection of the

pressure retaining portions of the sleeve and parent tube. Inservice

inspection is performed on all sleeves following installation to

ensure that each sleeve has been properly installed and is

structurally sound. Periodic inspections are performed in subsequent

refuel outages to monitor sleeve degradation on a sample basis. The

eddy current technique used for inspection will be capable of

detecting both axial and circumferential flaws. A 20% sample of the

sleeves are inspected each refuel outage. In the event that an

imperfection exceeding the repair limit is detected an additional

20% sample will be inspected. The inspection scope is expanded to

100% of the sleeves should a repairable defect be found in the

second sample. Tubes that contain defects in a sleeve, which exceed

the repair limit, will be removed from service. This ensures that

sleeve and tube structural integrity is maintained.

The proposed TS change to support the installation of TIG welded

sleeves does not adversely impact any previously evaluated design

basis accident. The effect of sleeve installation on the performance

of the SG was analyzed for heat transfer, flow restriction, and

steam generation capacity. The sleeves reduce the risk of primary to

secondary leakage in the SG. The installation of ABB/CE sleeve

results in a hydraulic flow restriction that is dependent on the

number and types of sleeves installed. The reduction in primary

system flow rate is a small percentage of the flow rate reduction

seen from plugging one tube and is a preferable alternative when

considering core margins based on minimum reactor coolant system

flow rates. The sleeving installation will result in a resistance to

primary coolant flow through the tube for other evaluated accidents.

The results of the analyses and testing, as well as industry

operating experience, demonstrate that the sleeve assembly is an

acceptable means of maintaining tube integrity. In summary,

installation of sleeves does not substantially affect the primary

system flow rate or the heat transfer capability of the steam

generators.

The sleeve sample size has been increased from 3% of the sleeved

tubes in all four steam generators to include an eddy current

inspection of a minimum of 20% of each sleeve design installed.

Increasing the sample size of the sleeves to be inspected will

increase the monitoring of tubes using sleeves for any further

degradation while they remain in service. If the sample identifies a

sleeve with an imperfection of greater than the repair limit, an

additional 20% of the sleeves shall be inspected. The sleeves that

have identified imperfections of greater than the repair limit shall

be removed from service. Increasing the monitoring of the sleeves

will assist in the early detection of a tube or sleeve imperfection

and limit the probability of occurrence of an accident previously

evaluated in the UFSAR.

Installation of the sleeves can be used to repair degraded tubes

by returning the condition of the tubes to their original design

basis condition for tube integrity and leak tightness during all

plant conditions. The tube bundle overall structural and leakage

integrity will be increased with the installation of the sleeves

reducing the risk of primary to secondary leakage in the SG while

maintaining acceptable reactor coolant system flow rates. Therefore

sleeving will not increase the probability of occurrence of an

accident previously evaluated.

Removal of the BWNT kinetically welded sleeve process as an

approved SG tube repair methodology and not completing the

additional corrosion testing necessary to establish the design life

for the BWNT kinetically welded sleeve in the presence of a crevice

will have no affect on plant operations. There are currently no BWNT

kinetically welded sleeves installed in the Byron or Braidwood SGs.

Had there been, plant operations would have still been bounded by

the existing SGTR analysis in the Byron and Braidwood UFSAR.

Therefore, these proposed changes do not involve a significant

increase in the probability or consequences of an accident

previously evaluated.

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

or different kind of accident from any accident previously

evaluated.

The implementation of the proposed sleeving process will not

introduce significant or adverse changes to the plant design basis.

Stress and fatigue analyses of the repair has shown the ASME Code

and RG 1.121 allowable values are met. Implementation of TIG welded

sleeving maintains overall tube bundle structural and leakage

integrity at a level consistent with that of the originally supplied

tubing. Leak and mechanical testing of the sleeves support the

conclusions that the sleeve retains both structural and leakage

integrity during all conditions. Repair of a tube with a sleeve does

not provide a mechanism that result in an accident outside of the

area affected by the sleeve.

Any hypothetical accident as a result of potential tube or

sleeve degradation in the repaired portion of the tube is bounded by

the existing SGTR analysis. The SGTR analysis accounts for the

installation of sleeves and the impact on current plugging level

analyses. The sleeve design does not affect any other component or

location of the tube outside of the immediate area repaired.

The current Technical Specification 3.4.6.2.c primary to

secondary leakage limit of 150 gpd through any one SG ensures that

SG tube integrity is maintained in the event of an MSLB or LOCA. The

limit will provide for leakage detection and a plant shutdown in the

event of the occurrence of an unexpected single crack resulting in

excessive tube leakage. The leakage limit also provides for early

detection and a plant shutdown prior to a postulated crack reaching

critical crack lengths for MSLB conditions.

Inservice inspections are performed following sleeve

installation to ensure proper weld fusion has occurred to maintain

structural integrity. The post installation inspection also serves

as baseline data to be used for comparison during future

inspections. Periodic eddy current inspections monitor the pressure

retaining portions of the sleeve and parent tube for degradation.

Eddy current techniques will be employed that are sensitive to axial

and circumferential degradation.

Increasing the sample size of tubes repaired using either

sleeving process during each scheduled inservice inspection will

increase the monitoring of these tubes for any further degradation.

The improved monitoring and evaluation of the tube and the sleeves

assures tube structural integrity is maintained or the tube is

removed for service.

Corrosion testing of typical sleeve-tube configurations was

performed to evaluate local stresses, sleeve life, and resistance to

primary and secondary side corrosion. The tests were performed on

stress relieved and as-welded (non-stress relieved) sleeve-tube

joints. Using the corrosion test data in conjunction with finite

element analyses of the local stress, the stress relieved joint life

was determined to be in excess of 40 years. The ABB/CE TIG welded

sleeve operating experience in the industry has shown no sleeve

failures due to service induced degradation in sleeves that were

installed with acceptable inspection results. This experience

includes the stress relieved and

[[Page 35066]]

as-welded sleeve configurations. ComEd will stress relieve all sleeves

at Byron and Braidwood as specified in the Technical Report.

Removal of the BWNT kinetically welded sleeve process as an

approved SG tube repair methodology and not completing the

additional corrosion testing necessary to establish the design life

for the BWNT kinetically welded sleeve in the presence of a crevice

will not create the possibility of a new or different type of

accident from any accident previously evaluated. Repair of an SG

tube with a BWNT kinetically welded sleeve would not have provided a

mechanism that resulted in an accident outside of the area affected

by the sleeve. Any hypothetical accident as a result of potential

tube or sleeve degradation in the repaired portion of the tube would

have been bounded by the existing SGTR analysis. The SGTR analysis

accounts for the installation of sleeves and the impact on current

plugging level analyses. The sleeve design does not affect any other

component or location of the tube outside of the immediate area

repaired. Furthermore, there are currently no BWNT kinetically

welded sleeves installed in the Byron or Braidwood SGs.

Therefore, the proposed changes do not create the possibility of

a new or different type of accident from any accident previously

evaluated.

3. The proposed change does not involve a significant reduction

in a margin of safety.

The TIG welded sleeving repair of degraded steam generator tubes

has been shown by analysis to restore the integrity of the tube

bundle to its original design basis condition. The safety factors

used in the design of the sleeves for the repair of degraded tubes

are consistent with the safety factors in the ASME Boiler and

Pressure Vessel Code used in steam generator design. The design of

the ABB/CE SG sleeves has been verified by testing to preclude

leakage during normal and postulated accident conditions.

The portions of the installed sleeve assembly which represents

the reactor coolant pressure boundary can be monitored for the

initiation and progression of sleeve/tube wall degradation, thus

satisfying the requirement of RG 1.83. The portion of the SG tube

bridged by the sleeve joints is effectively removed from the

pressure boundary, and the sleeve then forms the new pressure

boundary. The sleeve enhances the safety of the plant by

reestablishing the protective boundaries of the steam generator.

Keeping the tube in service with the use of a sleeve instead of

plugging the tube and removing it from service increases the heat

transfer efficiency of the steam generator. During each scheduled

inservice inspection, each sleeve inspected and found to have

unacceptable degradation shall be removed from service. The effect

on the design transients and the accident analyses have been

reviewed based on the installation of sleeves equal to the tube

plugging level coincident with the minimum reactor coolant flow

rate. Evaluation of the installation of sleeves was based on the

determination that LOCA evaluations for the licensed minimum reactor

coolant flow bound the combined effect of tube plugging and sleeving

up to an equivalent of the actual plugging limit. Sleeving results

in a fractional amount of the plugging limitation of one tube and is

a preferable alternative when considering core margins based on

minimum reactor coolant system flow rates. The sleeving installation

will result in a resistance to primary coolant flow through the

tube. The primary coolant flow through the ruptured tube is reduced

by the influence of the installed sleeve, thereby reducing the

consequences to the public due to a SGTR event.

A SG sleeve removes an indication of a possible leak source from

the reactor coolant system (RCS) pressure boundary, eliminating the

potential of a primary-to-secondary leak. The structural integrity

of the tube is maintained by the sleeve and sleeve-to-tube joint.

Installation of either tube sheet or tube support plate sleeves

will increase the protective boundaries of the steam generators and

will not reduce the margin of safety.

Removal of the BWNT kinetically welded sleeve process as an

approved SG tube repair methodology and not completing the

additional corrosion testing necessary to establish the design life

for the BWNT kinetically welded sleeve in the presence of a crevice

will not result in a reduction in the margin of safety. There are

currently no BWNT kinetically welded sleeves installed in the Byron

or Braidwood SGs. SG tube integrity will be maintained by applying

an alternate NRC approved repair methodology or removing the SG tube

from service by plugging.

Therefore, the proposed changes do 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 10 CFR 50.92(c) are

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

requested amendments involve no significant hazards consideration.

Local Public Document Room location: For Byron, the Byron Public

Library District, 109 N. Franklin, P.O. Box 434, Byron, Illinois 61010;

for Braidwood, the Wilmington Public Library, 201 S. Kankakee Street,

Wilmington, Illinois 60481.

Attorney for licensee: Michael I. Miller, Esquire; Sidley and

Austin, One First National Plaza, Chicago, Illinois 60603.

NRC Project Director: Robert A. Capra.

Commonwealth Edison Company, Docket Nos. 50-373 and 50-374, LaSalle

County Station, Units 1 and 2, LaSalle County, Illinois

Date of amendment request: April 11, 1995.

Description of amendment request: The proposed amendments would

allow a one-time extension of specific LaSalle, Units 1 and 2, 18 month

Technical Specification Surveillance Requirements to allow surveillance

testing to coincide with the LaSalle, Unit 1, seventh refueling outage

(L1R07). The shutdown for L1R07 has been rescheduled from September

1995 until early 1996. The proposed extensions apply to: Calibrations

and functional testing of isolation actuation instrumentation,

emergency core cooling system actuation instrumentation, and

recirculation pump trip actuation instrumentation; leakage testing of

reactor coolant system isolation valves; inspection of fire rated

seals; functional testing of mechanical snubbers; inspections of

emergency diesel generators; and testing of batteries, battery

chargers, and other electrical components.

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

consequences of an accident previously evaluated because:

The proposed change is temporary and allows a one-time extension

of specific surveillance requirements for Unit 1 Cycle 7 to allow

surveillance testing to coincide with the seventh refueling outage.

The proposed surveillance interval extension is short and will not

cause a significant reduction in system reliability nor affect the

ability of the systems to perform their design function. Current

monitoring of plant conditions and continuation of the surveillance

testing required during normal plant operation will continue to be

performed to ensure conformance with Technical Specification

operability requirements. Therefore, this change does not involve a

significant increase in the probability or consequences of an

accident previously evaluated.

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

accident from any accident previously evaluated because:

Extending the surveillance interval for the performance of

specific testing will not create the possibility of any new or

different kind of accidents. No changes are required to any system

configurations, plant equipment, or analyses. Therefore, this change

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

accident from any accident previously evaluated.

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

because:

Surveillance interval extensions will not impact any plant

safety analyses since the assumptions used will remain unchanged.

The safety limits assumed in the accident analyses and the design

function of the equipment required to mitigate the consequences of

any postulated accidents will not be changed since only the

surveillance test interval is being extended. Historical performance

generally indicates a high degree of reliability, and surveillance

[[Page 35067]]

testing performed during normal plant operation will continue to be

performed to verify continued Operability of affected systems,

structures and components. Therefore, the plant will be maintained

within the analyzed limits, and the proposed extension will not

significantly 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

requested amendments involve no significant hazards consideration.

Local Public Document Room location: Jacobs Memorial Library,

Illinois Valley Community College, Oglesby, Illinois 61348.

Attorney for licensee: Michael I. Miller, Esquire; Sidley and

Austin, One First National Plaza, Chicago, Illinois 60603.

NRC Project Director: Robert A. Capra.

Commonwealth Edison Company, Docket Nos. 50-373 and 50-374, LaSalle

County Station, Units 1 and 2, LaSalle County, Illinois

Date of amendment request: May 19, 1995.

Description of amendment request: The proposed amendments would

revise the technical specification requirement to verify each fire

protection valve is in the correct position at least once per 31 days.

The proposed change will retain a monthly visual inspection of the fire

protection valves that are accessible during plant operation. However,

the interval for visual surveillance of those valves considered not

accessible during plant operation will be changed to at least once per

18 months.

Basis for proposed no significant hazards consideration

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

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

(1) Involve a significant increase in the probability or

consequences of an accident previously evaluated because: The

proposed change does not involve a significant increase in the

probability or consequences of an accident previously evaluated in

the UFSAR [Updated Final Safety Analysis Report]. The proposed

change only changes the testing frequency for valves that are

inaccessible during power operation. A check of the LaSalle LER

database for the entire operating lifetime of LaSalle Units 1 and 2

was performed, and there has not been any instances in which any

Technical Specification related Fire Protection valves have been

found out of position. Therefore, the change to the frequency of

testing will have no affect on the capability of fire suppression

water systems, since all Technical Specification fire protection

valves, both accessible and inaccessible at power operation, have a

plant history of 100% correct valve lineup during monthly

surveillances. Additionally, all fire protection valves that are in

the fire suppression water flow path are either locked or seal wired

in the required position at all times. The change does not impact

the probability of any fire or other accident occurrence. Therefore,

the proposed change does not cause an increase in the probability or

consequences of an accident previously evaluated.

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

accident from any accident previously evaluated because:

The proposed change does not involve a significant increase in

the probability or consequences of an accident previously evaluated

in the UFSAR. The proposed change only changes the testing frequency

for valves that are inaccessible during power operation. The change

to the frequency of testing will have no effect on the capability of

fire suppression water systems, since the valves, both accessible

and inaccessible at power operation, have a plant lifetime history

of 100% correct valve lineup during monthly surveillances.

Additionally, these valves are locked or sealed in the required

position at all times. The change does not alter the performance of

the fire suppression water system, and therefore introduces no new

failure modes. With no alteration or degradation to equipment or

system operation, the change introduces no new accident or

malfunction.

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

because:

The proposed change does not reduce the margin as defined in the

bases for any Technical Specification. The proposed change only

changes the testing frequency for all Technical Specification fire

protection valves that are inaccessible during power operation. The

plant history of 100% correct valve lineup for the Technical

Specification fire protection valves, combined with the fact that

these valves are always locked or sealed in the required position

ensures that the bases' minimum OPERABILITY requirements of the fire

suppression systems are met.

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

requested amendments involve no significant hazards consideration.

Local Public Document Room location: Jacobs Memorial Library,

Illinois Valley Community College, Oglesby, Illinois 61348.

Attorney for licensee: Michael I. Miller, Esquire; Sidley and

Austin, One First National Plaza, Chicago, Illinois 60603.

NRC Project Director: Robert A. Capra.

Commonwealth Edison Company, Docket Nos. 50-295 and 50-304, Zion

Nuclear Power Station, Units 1 and 2, Lake County, Illinois

Date of amendment request: May 31, 1995.

Description of amendment request: The proposed amendments would

revise the Technical Specifications and incorporate new acceptance

criteria for steam generator tubes with degradation in the tubesheet

roll expansion region.

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 of occurrence or consequences of an accident

previously evaluated.

Application of the F* criteria to degraded steam generator tubes

will not affect any of the initiators or precursors of any accident

previously evaluated. Application of the proposed change will not

increase the likelihood that a transient initiating event will occur

because transients are initiated by equipment malfunction and/or

catastrophic system failure. The proposed change will allow a new

criteria to be applied to disposition steam generator tubes that are

degraded in the tubesheet roll transition region. The F* criteria

specify a minimum length of tubing which must be free from any

indication of degradation. Below the F* length, any type or size of

indication, including complete circumferential through wall

cracking, will not impact the structural integrity of the tube with

respect to pull out forces during normal operation or accident

conditions, and does not significantly affect the leakage behavior

of the tube. While the Zion UFSAR does not specifically address the

Feedwater Line Break (FLB) accident, the FLB event was used as the

limiting event in the evaluation of the F* criteria. The FLB

pressure differential of 2650 psi maximizes the axial loading on the

tube for pull out considerations and is bounding. In addition, the

close proximity of the tubesheet to the tube will prevent tube

rupture or collapse of the tube in the tubesheet span. Because

application of the F* criteria will ensure that degraded tubes will

provide the same structural integrity as an original undegraded tube

during normal operation and accident and accident conditions, the

probability of occurrence of an accident previously evaluated is not

significantly increased.

Application of the F* criteria will not significantly increase

the consequences of any accident previously evaluated. The F*

criteria ensure that sufficient length of undegraded tube exists to

maintain structural integrity and preclude significant leakage. Due

to the proximity of the tubesheet to the tube, any leakage from

degradations below the F* length would be negligible and would be

well below the Technical Specification limits established for steam

generator

[[Page 35068]]

leakage. Tube rupture as a result of indications below the F* distance

is precluded because the tubesheet prevents outward expansion of the

tube in response to internal pressure.

The relationship between the tubesheet region leak rate at the

most limiting postulated accident conditions relative to that for

normal plant operating conditions has been assessed. For the

postulated leak source within the roll expansion, increasing the

differential pressure on the tube on the tube wall increases the

driving head for the leak; however, it also increases the tube to

tubesheet loading.

For a leak source below the F* Distance, the maximum assumed

pressure differential results in an insignificant leak rate relative

to that which could be associated with normal plant operation. This

is a result of the increased tube to tubesheet loading associated

with the increased differential pressure. Thus for a circumferential

indication within the roll expansion that is left in service in

accordance with F* criteria, any leakage under accident conditions

would be less than that experienced under normal operating

conditions. Therefore, any leakage under accident conditions would

be less than the existing Technical Specification leakage limit,

which is consistent with accident analysis assumptions. Steam

generator tube integrity must be maintained under the postulated

loss of coolant accident condition of secondary-to-primary

differential pressure. Based on tube collapse strength

characteristics, the constraint provided to the tube by the

tubesheet gives a margin between the tube collapse strength and the

limiting secondary-to-primary differential pressure condition, even

in the presence of circumferential or axial indications. The maximum

secondary to primary differential pressure during a postulated LOCA

is 1005 psi. This value is significantly below the residual preload

between the tubes and the tube sheet. Therefore, no significant

secondary to primary leakage would be expected to occur.

In addition, the proposed changes will not affect the ability to

safely shut down the operating unit and mitigate the consequences of

an accident because the proposed changes will not necessitate

changes to the emergency procedures governing accident conditions or

plant recovery.

Administrative and typographical changes are proposed to correct

previous grammatical errors, to eliminate a parenthetical note that

could cause confusion when applying the proposed requirements, and

to make the terminology used in the Bases section consistent with

the definitions provided in Specification 4.3.1. Those proposed

changes will not increase the probability of occurrence or

consequence of any 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 to the Technical Specifications do not

involve the addition of any new or different types of safety related

equipment nor do they involve the operation of any equipment

required for safe operation of the facility in a manner different

from those addressed in the UFSAR. No safety related equipment or

function will be altered as a result of the proposed changes. Also,

the procedures governing normal plant operation and recovery from an

accident are not changed by the application of the F* criteria. The

F* criteria will allow the use of an alternate method to plugging or

sleeving to repair steam generator tubes with degradation in the

tubesheet region. The F* criteria ensure that both the structural

integrity and leak tight nature of the steam generator tube will be

equivalent to the original tube. Since no new failure modes or

mechanisms are introduced by the proposed changes, no new or

different type of accident is created.

Administrative and typographical changes are proposed to correct

previous grammatical errors, to eliminate a parenthetical note that

could cause confusion when applying the proposed requirements, and

to make the terminology used in the Bases section consistent with

the definitions provided in Specification 4.3.1. Those proposed

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

of accident from those previously evaluated.

3. The proposed changes do not involve a significant reduction

in a margin of safety.

Plant safety margins are established through Limiting Conditions

for Operation (LCOs), limiting safety system settings, and safety

limits specified in Technical Specifications. There will be no

changes to the LCOs, limiting safety system settings, or the safety

limits as a result of the proposed changes. Application of the F*

criteria will allow degraded steam generator tubes to be repaired by

an alternative method to plugging or sleeving. Steam generator tube

plugging decreases the total primary reactor coolant flow rate and

heat transfer capability of the steam generator. While steam

generator tube sleeving only slightly reduces the reactor coolant

flow rate, large numbers of sleeves can have a measurable effect on

flow rate and can complicate steam generator tube inspection

activities.

Application of the F* criteria will allow a repair method that

will restore the integrity of degraded steam generator tubes and

will not adversely affect primary system flow rate or heat transfer

capability. Application of the F* criteria will preserve the heat

transfer capability of the steam generators and will maintain the

design margins assumed in the analyses contained in the UFSAR. The

alternate repair method will also be less complicated, faster, and

will reduce personnel occupational exposure significantly. Based on

the above discussion it is concluded that the proposed changes will

not significantly reduce a margin of safety.

Administrative and typographical changes are proposed to correct

previous grammatical errors, to eliminate a parenthetical note that

could cause confusion when applying the proposed requirements, and

to make the terminology used in the Bases section consistent with

the definitions provided in Specification 4.3.1. Those proposed

changes will not impact any 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

requested amendments involve no significant hazards consideration.

Local Public Document Room location: Waukegan Public Library, 128

N. County Street, Waukegan, Illinois 60085.

Attorney for licensee: Michael I. Miller, Esquire; Sidley and

Austin, One First National Plaza, Chicago, Illinois 60603.

NRC Project Director: Robert A. Capra.

Entergy Operations, Inc., Docket Nos. 50-313 and 50-368, Arkansas

Nuclear One, Unit Nos. 1 and 2 (ANO-1&2), Pope County, Arkansas

Date of amendment request: April 4, 1995.

Description of amendment request: The proposed amendments revise

requirements associated with the ventilation system that services both

the Unit 1 and Unit 2 control rooms.

Basis for proposed no significant hazards consideration

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

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

Criterion 1--Does Not Involve a Significant Increase in the Probability

or Consequences of an Accident Previously Evaluated.

The control room emergency ventilation and air conditioning

systems are not initiators of an accident previously evaluated.

Extension of the allowable outage time for one inoperable control

room emergency air conditioning system from 7 days to 30 days is

acceptable based on the low probability of an event occurring that

would require control room isolation and a concurrent or subsequent

failure of the remaining operable control room emergency air

conditioning system. An evaluation using probabilistic safety

assessment techniques has shown the frequency of this event to be at

an acceptably low level (4.67E-6/yr). The ANO-1 surveillance

requirements for the control room emergency ventilation and air

conditioning system has been updated for consistency with the ANO-2

requirements and are consistent with RG 1.52, March 1978, Revision

2. The relaxation in the ANO-2 Mode of Applicability for the control

room radiation monitoring instrumentation is acceptable based on the

fuel handling accident analysis dose consequences. The analysis

assumes that the control room emergency ventilation system is

actuated during a fuel handling accident in the containment

building. This analysis also shows that the dose consequences to the

control room operators are acceptable in the event of a fuel

handling analysis in the

[[Page 35069]]

auxiliary building, assuming that the normal control room ventilation

system only is in operation. When the unit is in Mode 5 or Mode 6

(with no handling of irradiated fuel in the containment building),

no accident condition has been identified that would require the

control room emergency ventilation system to actuate due to high

radiation. The remainder of the changes have been made for

consistency between the ANO-1 and ANO-2 TS and are considered to be

administrative in nature.

Therefore, this change does not involve a significant increase

in the probability or consequences of any accident previously

evaluated.

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

of Accident from any Previously Evaluated

The control room emergency ventilation and air conditioning

systems are not accident initiators. The proposed changes introduce

no new mode of plant operation and no new possibility for an

accident is introduced by modifying the ANO-1 surveillance testing

requirements for the control room emergency ventilation and air

conditioning systems.

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

or different kind of accident from any previously evaluated.

Criterion 3--Does Not Involve a Significant Reduction in the Margin of

Safety

With the exception of the AOT extension and the relaxation of

the ANO-2 Mode of Applicability for the control room radiation

monitoring instrumentation, all the ANO-1 and ANO-2 changes are

considered administrative or more restrictive and are intended to

clarify and make consistent the requirements of the control room

emergency habitability equipment. Although the AOT extension does

involve an incremental reduction in the margin of safety due to a

slight increase in the frequency of an event requiring control room

isolation, followed by failure of the operable emergency control

room chiller, a probabilistic safety assessment has shown this

slight increase in frequency (approximately 3.58E-6/yr) to be

acceptably low. The relaxation in the ANO-2 Mode of Applicability

for the control room radiation monitoring instrumentation is

acceptable based on the fuel handling accident analysis dose

consequences. The analysis assumes that the control room emergency

ventilation system is actuated during a fuel handling accident in

the containment building. This analysis also shows that the dose

consequences to the control room operators are acceptable in the

event of a fuel handling analysis [sic., accident] in the auxiliary

building, assuming that the normal control room ventilation system

only is in operation. When the unit is in Mode 5 or Mode 6 (with no

handling of irradiated fuel in the containment building), no

accident condition has been identified that would require the

control room emergency ventilation system to actuate due to high

radiation.

Therefore, this 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 10 CFR 50.92(c) are

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Tomlinson Library, Arkansas

Tech University, Russellville, AR 72801.

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

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

NRC Project Director: William D. Beckner.

Entergy Operations, Inc., Docket Nos. 50-313 and 50-368, Arkansas

Nuclear One, Unit Nos. 1 and 2 (ANO-1&2), Pope County, Arkansas

Date of amendment request: April 4, 1995.

Description of amendment request: The proposed amendments delete

requirements to perform inservice inspections of reactor coolant pump

flywheels at both Unit 1 and Unit 2.

Basis for proposed no significant hazards consideration

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

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

Criterion 1--Does Not Involve a Significant Increase in the Probability

or Consequences of an Accident Previously Evaluated.

Missile generation from a reactor coolant pump (RCP) flywheel

could damage the reactor coolant system, the containment, or other

equipment or systems important to safety. The fracture mechanics

analyses conducted to support the change shows that a preexisting

crack sized just below detection level will not grow to the flaw

size necessary to create flywheel missiles within the life of the

plant. This analysis conservatively assumes minimum material

properties, maximum flywheel accident speed, location of the flaw in

the highest stress area and a number of startup/shutdown cycles

eight times greater than expected. Since an existing flaw in the

flywheel will not grow to the allowable flaw size under normal

operating conditions or to the critical flaw size under LOCA

conditions over the life of the plant, elimination of inservice

inspections for such cracks during the plant's life will not involve

a significant increase in the probability of an accident previously

considered.

The proposed changes do not increase the amount of radioactive

material available for release or modify any systems used for

mitigation of such releases during accident conditions. Therefore,

these changes do not involve a significant increase in the

consequences of any accident previously evaluated.

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

of Accident from any Previously Evaluated

The proposed changes will not change the design, configuration,

or method of operation of the plant and therefore, will not create

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

previously evaluated.

Criterion 3--Does Not Involve a Significant Reduction in the Margin of

Safety

Significant conservatisms have been used for calculating the

allowable flaw size, critical flaw size and crack growth rate in the

RCP flywheels. These include minimum material properties, maximum

flywheel accident speed, location of the flaw in the highest stress

area and a number of startup/shutdown cycles eight times greater

than expected. Since an existing flaw in the flywheel will not grow

to the allowable flaw size under normal operating conditions or to

the critical flaw size under LOCA conditions over the life of the

plant, elimination of inservice inspections for such cracks during

the plant's life will 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 10 CFR 50.92(c) are

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Tomlinson Library, Arkansas

Tech University, Russellville, AR 72801.

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

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

NRC Project Director: William D. Beckner.

Entergy Operations, Inc., Docket No. 50-368, Arkansas Nuclear One, Unit

No. 2, Pope County, Arkansas

Date of amendment request: April 4, 1995.

Description of amendment request: The proposed amendment revises

surveillance requirements associated with the main turbine steam

valves.

Basis for proposed no significant hazards consideration

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

provided its analysis of the issue of no significant hazards

consideration, which is presented below:

Criterion 1--Does Not Involve a Significant Increase in the Probability

or Consequences of an Accident Previously Evaluated.

Modifying the surveillance frequency of the main turbine-

generator (MTG) overspeed protection system introduces no new

failure mechanism for the machine, so the consequences, of a

postulated MTG overspeed event are no different than those

previously evaluated.

[[Page 35070]]

As explained in NUREG-1366, ``Improvements to Technical

Specifications Surveillance Requirements,'' the present surveillance

test frequency requirements were developed for fossil units and

carried over to nuclear units due to the similarity in design.

However, the particulate concentration, phosphate chemistry and

higher steam temperatures present in earlier fossil secondary

systems, which were major contributing factors to problems

identified by these tests, are not present in the Arkansas Nuclear

One-Unit 2 (ANO-2) secondary systems. The operating history of

turbine valves at ANO-2 is very good, with no failures identified

during the performance of overspeed protection system surveillance

testing. Therefore, that change does not involve a significant

increase in the probability of any accident previously evaluated.

Therefore, this change does not involve a significant increase

in the probability or consequences of an accident previously

evaluated.

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

of Accident from any Previously Evaluated.

Because the proposed changes do not alter the design,

configuration, or method of operation of the plant, they do not

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

any previously evaluated.

Criterion 3--Does Not Involve a Significant Reduction in the Margin of

Safety.

These proposed changes do not alter the acceptance of any

surveillance requirements, alter any assumptions used in accident

analysis, change any actuation setpoints, nor allow operations in

any configuration not previously evaluated. This change in

surveillance frequency is based on an operating history of the

turbine overspeed protection system which indicates that reducing

the test frequency will have no adverse impact on the continued safe

operation of the unit.

Therefore, this 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 10 CFR 50.92(c) are

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Tomlinson Library, Arkansas

Tech University, Russellville, AR 72801

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

Strawn, 1400 L Street, NW., Washington, DC 20005-3502.

NRC Project Director: William D. Beckner.

Florida Power Corporation, et al., Docket No. 50-302, Crystal River

Nuclear Generating Plant, Unit No. 3, Citrus County, Florida

Date of amendment request: May 31, 1995.

Description of amendment request: The proposed amendment would

revise the the Technical Specifications (TS) for the Crystal River Unit

3 to facilitate a 24 month operating cycle by changing the surveillance

interval for appropriate TS surveillance requirements that are

generally performed during a refueling outage. Additionally, the

functional description and the ``Allowable Value'' for three Reactor

Protection System and one Emergency Feedwater Initiation and Control

System setpoints would be revised. The quantitative limits for

determining the operational status of the reactor coolant pumps, the

main feedwater pumps, and the main turbine would be relocated from the

TS to the Final Safety Analysis Report (FSAR). The surveillance

associated with the high radiation setpoint for control room isolation

would also be changed to reflect that the setpoint is an ``approximate

value'' instead of an ``Allowable value''. The current specified

surveillance interval for some equipment and systems which were not re-

evaluated or which could not be justified by the evaluation process

would not be changed.

Specifically:

1. TS Surveillance Requirements (SR) 3.3.1.6, SR 3.3.5.3, SR

3.3.6.1, SR 3.3.9.2, SR 3.3.10.2, SR 3.3.11.3, SR 3.3.17.2, SR

3.3.18.2, and SR 3.9.2.2 would be revised to extend the surveillance

frequency from 18 to 24 months. Also, in TS SR 3.3.17.2 a note would be

added indicating the frequency for Function 12 is 18 months.

2. In TS Table 3.3.1-1,

(a) the Function for ``Reactor Coolant Pump Power Monitor (RCPPM)''

would be changed to ``Reactor Coolant Pumps,'' and the ``Allowable

Value'' column for this function would be revised to delete the

quantitative value and to indicate ``More than one pump tripped'',

(b) the Function for ``Main Turbine Trip (Control Oil Pressure)''

would be changed to ``Main Turbine,'' and the Allowable Value is

changed to ``Turbine Tripped'' and

(c) the Function for ``Loss of Both Main Feedwater Pumps (Control

Oil Pressure)'' would be changed to ``Main Feedwater Pumps,'' and the

Allowable Value is changed to ``Both Pumps Tripped''

3. In TS Table 3.3.11-1, Function 1.a would be changed from ``EFW

Initiation--Loss of MFW Pumps (Control Oil Pressure)'' to ``EFW

Initiation--Main Feedwater Pumps,'' and the Allowable Value is changed

to ``Both Pumps Tripped.''

4. In TS SR 3.3.16.3, the CHANNEL CALIBRATION setpoint would be

changed from an allowable value to an approximate 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:

1. Operation of the facility in accordance with the proposed

amendment would not involve a significant increase in the

probability of occurrence or the consequences of an accident

previously evaluated. The proposed amendment extends the interval

between successive refueling outage based surveillances to once

every 24 months for those surveillances evaluated herein and,

maintains the existing surveillance interval restriction for those

systems and equipment not evaluated for extension. The reliability

of systems and components relied upon to prevent or mitigate the

consequences of accidents previously evaluated is not degraded

beyond that obtained from the currently defined refueling outage

interval. Assurance of system and equipment availability is

maintained. This change does not involve any change to system or

equipment configuration. Therefore, this change does not increase

the probability of occurrence or the consequences of an accident

previously evaluated.

2. Operation of the facility in accordance with the proposed

amendment would not create the possibility of a new or different

kind of accident from any accident previously evaluated. The

proposed amendment extends the interval between successive refueling

outage based surveillances to once every 24 months for those

surveillances evaluated herein and maintains the existing

surveillance interval restriction for those systems and equipment

not evaluated for extension. This change does not involve any change

to system or equipment configuration. Therefore, this change is

unrelated to the possibility of creating a new or different kind of

accident from any previously evaluated.

3. Operation of the facility in accordance with the proposed

amendment would not involve a significant reduction in a margin of

safety. The proposed amendment extends the interval between

successive refueling outage based surveillances to once every 24

months for the surveillances evaluated herein, and maintains the

existing surveillance interval restriction for those systems and

equipment not evaluated for extension. The reliability of systems

and components is not degraded beyond that obtained from the

currently defined refueling outage interval. Assurance of system and

equipment availability is maintained.

Therefore, it is concluded that operation of the facility in

accordance with the proposed amendment does not involve a

significant reduction in a margin of safety. The proposed extension

of the refueling outage interval surveillances to once every 24

months does not degrade the reliability of systems and components

beyond that obtained from the currently defined refueling outage

interval.

[[Page 35071]]

Reliable performance of the systems and equipment effected by this

change has been demonstrated.

Implementation of the proposed amendment will maintain the

required level of assurance of system and equipment availability.

The surveillance interval for systems and equipment that have not

been evaluated for extension are excluded from this request. Thus,

operation of the facility in accordance with the proposed amendment

involves no significant hazards considerations.

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

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

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Coastal Region Library, 8619

W. Crystal Street, Crystal River, Florida 32629.

Attorney for licensee: A.H. Stephens, General Counsel, Florida

Power Corporation, MAC-A5D, P. O. Box 14042, St. Petersburg, Florida

33733.

NRC Project Director: David B. Matthews.

Florida Power Corporation, et al., Docket No. 50-302, Crystal River

Nuclear Generating Plant, Unit No. 3, Citrus County, Florida.

Date of amendment request: May 31, 1995.

Description of amendment request: The proposed amendment would

revise the technical specifications (TS) for the Crystal River Nuclear

Plant Unit 3 (CR3) relating to the Once Through Steam Generator's

(OTSG's) tube inspection acceptance criteria. Currently, the TS specify

repair limit for removing steam generator tubes from service based on a

structural evaluation of a simplified model of tubes with uniform

through wall (T/W) thinning. A recent tube-pull examination at CR3

identified a number of low signal-to-noise (S/N) tube eddy current

indications. The licensee indicated that these S/N indications are a

substantially different morphology from the model used to develop the

current TS inspection and acceptance limit. As a result of the small

signal amplitude associated with these S/N indications, they cannot be

accurately sized by conventional bobbin coil phase angle. Therefore,

the licensee proposed an alternate methodology for dispositioning the

S/N indications. The proposed criteria would address both wear and

Inter-Granular-Attack (IGA) degradation mechanisms. Crack-like eddy

current indications are not included within the proposed scope.

Specifically, the licensee proposed to:

A. Revise TS 5.6.2.10.2, page 5.0-14, ``The results of each sample

inspection shall be classified into one of the following three

categories:'' to read: ``The results of each bobbin coil sample

inspection shall be classified into one of the following three

categories:''

B. Revise the Note in TS 5.6.2.10.2, page 5.0-14, ``In all

inspections, previously degraded tubes whose degradation has not been

spanned by a sleeve must exhibit a significant increase in the

applicable imperfection size measurement (> +0.5V bobbin coil amplitude

increase for S/N indications or >10% further wall penetration for all

other imperfections) to be included in the below percentage

calculations.''

C. Revise the sentence in TS 5.6.2.10.4.a.2, page 5.0-16, ``Eddy-

current* * *as imperfections'' to read: S/N indications with a bobbin

coil amplitude 0.9V or other imperfection

20% of the nominal wall thickness caused by degradation

except where all such degradation has been spanned by the installation

of a sleeve.''

E. Add TS 5.6.2.10.4.a.7 ``Signal-to-Noise (S/N) indication means

an indication whose associated bobbin coil amplitude is a) is

changed to 49.6 psig (Unit 1) and 45.5 psig (Unit 2). These values

appear in Bases Sections B 3.6.1.1, B 3.6.1.2, and B 3.6.1.4 in each

unit's Technical Specifications.

Section 4.1.1.3 of NEDC-32405P discusses the peak short-term

containment pressure response which was recalculated for power

uprate conditions. Containment pressure and temperatures remain

below design limits and are essentially unchanged.

iv. The main condenser offgas gross gamma activity rate limit of

240 mci/second will not be changed for power uprate. A statement

that the current limit is conservative for power uprate conditions

was added to Bases Section 3.7.6 for both units.

The Bases derive the current 240 mci/second limit using a rated

core thermal power limit of 2436 MWt. A slightly higher limit could

be justified using the uprated power level. However, adequate margin

exists with the current limit.

v. The inservice hydrostatic and leak testing pressures shown in

Bases Section 3.10.1 are increased 33 psi and 30 psi, respectively.

This change affects each unit's Bases.

This change is a direct result of the 30 psi increase in normal

operating pressure proposed for power uprate. The leakage test is

normally performed at operating pressure and the hydrostatic test at

approximately 110 percent of operating pressure.

The above Bases changes Items i-v have been evaluated and will

not increase the probability or consequences of an accident

previously evaluated.

2. Will the changes create the possibility of a new or different

kind of accident from any accident previously evaluated?

Evaluation

The Operating License changes in power level and the associated

Technical Specifications changes discussed previously will not

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

any accident previously evaluated, as summarized below.

Equipment that could be affected by power uprate was evaluated.

No new operating mode, safety-related equipment lineup, accident

scenario, or equipment failure mode were identified. The full

spectrum of accident considerations defined in RG 1.70 was

evaluated, and no new or different kind of accident was identified.

Uprate uses already-developed technology and applies it within the

capabilities of existing plant equipment in accordance with

presently existing regulatory criteria to include NRC-approved

codes, standards, and methods. GE has designed BWRs of higher power

levels than the uprated power of any of the currently operating BWR

fleet, and no new power dependent accidents have been identified.

The Technical Specifications changes required to implement power

uprate require only minor modifications to the plant's

configuration. All changes were evaluated and found to be

acceptable.

3. Will the changes involve a significant reduction in the

margin of safety?

A. Rated Thermal Power is increased to 2558 MWt on page 3 of the

Unit 1 Operating License, page 4 of the Unit 2 Operating License,

and in Section 1.1 (Definitions) of the Unit 1 and Unit 2 Technical

Specifications.

Evaluation

The events analyzed in the FSAR were re-evaluated to demonstrate

that power uprate can be implemented without exceeding any

regulatory limit. Because the applicable safety analysis criteria

and limits are satisfied for power uprate, the margin of safety

associated with the safety limits and other limits identified in the

Technical Specifications will be maintained.

As discussed in NEDC-32405P, the safety margins prescribed by

the Code of Federal Regulations are maintained by meeting the

appropriate regulatory criteria. Similarly, the margins provided by

the application of the ASME design criteria are maintained. Section

11.4.2 of NEDC-32405P discusses the effects of power uprate on

safety margins for the following:

Fuel thermal limits Design basis accidents and the challenges to

fuel, containment, and radiological releases. Transient analyses.

Non-LOCA radiological releases. Environmental consequences.

These evaluations conclude that applicable safety analysis

criteria and limits are

[[Page 35075]]

satisfied, and thus, the margin of safety will not be significantly

reduced.

B. The surveillance test discharge pressure for the SLC pump at

41.2 gpm is increased from 1190 psig to 1201 psig. This value

appears in SR 3.1.7.7 and corresponding Bases Section B 3.1.7 in the

Unit 1 and Unit 2 Technical Specifications.

Evaluation

Power uprate operation will result in a 30 psi increase in

reactor operating pressure. Several pressure-dependent setpoints

(including SRV setpoints) will be increased to preserve current

margins. Increasing the pressure 11 psi, at which a 41.2 gpm flow

rate is developed, assures continued conformance to ATWS criteria at

uprated conditions. The surveillance test pressure is based on the

maximum pressure for an ATWS event during the time period when the

SLC pump is in operation. Section 6.5 of NEDC-32405P discusses the

capability of these positive displacement pumps. A small increase in

the SRV setpoints will have no effect on the rated injection flow to

the reactor.

For power uprate, the capability of the SLCS to respond with

adequate margin to an ATWS event was confirmed. The results are

reported in Section 9.3.1 of NEDC-32405P. The limiting ATWS event

was an inadvertent MSIV closure. The event was reanalyzed at uprate

conditions with the higher SRV setpoints and ATWS-RPT setpoints.

Peak vessel pressure was well below the ASME emergency limit of 1500

psig. The effect of power uprate on peak clad temperature and

maximum suppression pool temperature was judged to be negligible,

because the calculations showed no increase in fuel surface heat

flux or integrated SRV flow.

In summary, all ATWS criteria are satisfied and the SLC pumps

are capable of injecting the required amounts of sodium pentaborate

at uprated conditions. Therefore, there is no significant decrease

in the margin of safety.

C. The reactor vessel steam dome high pressure allowable value

for RPS instrumentation is increased 31 psi, consistent with the

nominal pressure increase for power uprate. The allowable value

appears in Section 3.3.1.1, Table 3.3.1.1-1, Function 3, in the Unit

1 and Unit 2 Technical Specifications.

Evaluation

The reactor vessel steam dome high pressure scram limit is

increased because the steam dome operating pressure is increased.

Operating pressure for uprated power is increased to assure that

satisfactory reactor pressure control is maintained. The operating

pressure was chosen on the basis of steam line pressure drop

characteristics and the steam flow capability of the turbine.

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 maximum stroke. An

operating dome pressure of 1035 psig, which is 30 psi higher than

the current operating dome pressure, is expected. Therefore, the

high pressure scram is increased approximately the same amount to

preserve existing margins to reactor trips.

The increases in the steam dome high pressure scram instrument

setpoints for uprated power were evaluated by determining whether

the high pressure scram, which is used as a backup to other scram

signals, provides adequate overpressure protection. The evaluation

demonstrates that the backup protection function, with the revised

setpoints, continues to provide adequate overpressure protection at

uprated power conditions by meeting the applicable ASME Code

criteria. Therefore, there is no significant decrease in the margin

of safety.

D. The ATWS reactor vessel steam dome high pressure RPT

allowable value is raised 80 psi. The allowable value appears in

Section 3.3.4.2, SR 3.3.4.2.3, in the Unit 1 and Unit 2 Technical

Specifications.

Evaluation

The ATWS-RPT high pressure setpoint initiates a trip of the

recirculation pumps, thereby adding negative reactivity following

events in which a scram does not (but should) occur. Section 5.1.3.2

of NEDC-32405P discusses this function in detail.

For power uprate, the capability of the SLCS to respond to a

postulated ATWS event with adequate margin was confirmed (Section

9.3.1 of NEDC-32405P). By reducing reactor power until the SLCS can

inject the required amounts of sodium pentoborate to achieve full

shutdown, the RPT also reduces suppression pool temperature for

isolation cases (also shown to be acceptable for power uprate

conditions in Section 9.3.1 of NEDC-32405P). Therefore, there is no

significant decrease in a margin of safety.

E. The LLS SRV arming pressure allowable value is increased 31

psi, consistent with the increase in operating pressure and high

pressure scram allowable value. The LLS arming pressure allowable

value appears in Section 3.3.6.3, Table 3.3.6.3-1, Function 1, in

the Unit 1 and Unit 2 Technical Specifications.

Evaluation

The allowable value for the LLS SRV high pressure arming

setpoint is increased, because the high pressure scram setpoint is

increased. No changes to the LLS arming logic associated with the

SRV tailpipe pressure switches, and the LLS opening and closing

pressure setpoints are proposed.

Since this proposed change only affects one of two arming

signals for LLS, the safety analyses are not affected; therefore,

there is not a significant change in the margin of safety.

F. Lower the permissible rod line for SLO below 45 percent core

flow from the 80 percent rod line to the 76 percent rod line. This

Technical Specifications limit appears in Section 3.4.1 (Figure

3.4.1-1) and corresponding Bases Section B 3.4.1 of the Unit 1 and

Unit 2 Technical Specifications.

Evaluation

This change to the power versus flow map restricted zone is made

to maintain the same operating constraints and stability margin that

were established for the current power level. This change avoids any

increase in the possibility of occurrence or any increase in the

potential effects of power oscillations. Therefore, there is no

significant decrease in a margin of safety.

G. The SRV lift setpoints in Surveillance Requirement 3.4.3.1

(both units) will be increased 30 psi.

Evaluation

The SRVs are designed to prevent overpressurization of the

reactor pressure vessel during abnormal operational transients. The

SRV lift setpoints are increased to accommodate the increase in

operating pressure that accompanies power uprate. The increase in

SRV setpoints ensures that adequate margins are maintained so that

the increase in dome pressure during normal operation does not

result in an increase in the number of unnecessary SRV actuations.

The setpoint increase also maintains the hierarchy of pressure

setpoints described in these proposed changes. Transient evaluations

include a + 3 percent tolerance to the nominal setpoints. As

described in Section 3.2 of NEDC-32405P, peak vessel pressure

increases by 3 percent but remains well below the 1375 psig ASME

Code limit. Therefore, there is no significant decrease in the

margin of safety.

H. The Limiting Condition for Operation (LCO) and Surveillance

Requirements for the maximum reactor steam dome pressure will be

increased from 1020 psig to 1058 psig. This requirement appears in

LCO 3.4.10, SR 3.4.10.1, and the corresponding Bases in the Unit 1

and Unit 2 Technical Specifications.

Evaluation

As discussed in the Technical Specifications Bases and in

Section 3.2 of NEDC-32405P, the maximum reactor dome pressure is an

initial condition of the vessel overpressure protection analysis,

which assumes a fast isolation of all four main steam lines by the

main steam isolation valves. It is also used as a sensitivity study

parameter for certain transient and LOCA events.

With this revised limit, peak vessel pressure remains below ASME

Code criteria, transient limits are maintained, and LOCA fuel

performance satisfies the requirements of 10 CFR 50.46 and 10 CFR

50, Appendix K. Therefore, there is no significant decrease in a

margin of safety.

I. The HPCI and RCIC surveillance test pressures in SRs 3.5.1.8

and 3.5.3.3, respectively, (both units) are increased 38 psi.

Evaluation

The allowable HPCI and RCIC surveillance test pressure is

increased to correspond with the increase in normal reactor

operating pressure and LCO/SR on maximum reactor pressure that

accompanies power uprate. (As discussed previously, the LCO on

reactor steam dome pressure is increased 38 psi.)

The purpose of the HPCI and RCIC surveillance test is to provide

periodic demonstration of the systems' ability to perform consistent

with the requirements of the analyses at the higher operating

pressure associated with power uprate conditions. An evaluation of

the HPCI and RCIC systems confirmed their ability to operate at

slightly higher turbine speed and provide design flow

[[Page 35076]]

at power uprate conditions. System performance will be confirmed during

the initial power ascension to uprated conditions (and periodically

thereafter per the Technical Specifications). Therefore, there is no

significant decrease in the margin of safety.

J. Bases Changes

Several changes to the Hatch Units 1 and 2 Technical

Specifications Bases are proposed for consistency with the power

uprate safety analyses. These proposed changes are in addition to

the Bases changes corresponding to proposed changes A through I.

i. The main steam line flow differential pressure setpoints, as

shown in Bases Section B 3.3.6.1.c, and the HPCI/RCIC high flow

differential pressure setpoints (Units 1 and 2 Bases Sections B

3.3.6.3.a and B 3.3.6.4.a) are changed.

The allowable values (in percent of rated) will not change for

power uprate operation. However, the actual differential pressure

will change due to the increase in steam flow and pressure.

ii. The HPCI and RCIC upper design pressure in Units 1 and 2

Bases Sections B 3.5.1 and B 3.5.3, respectively, is increased 34

psi.

The Bases changes support the design of these high pressure

systems to pump rated flow from approximately 150 psig up to a

pressure associated with the first group of SRV setpoints. This

proposed design pressure conservatively considers the 30 psi higher

nominal setpoints and 3 percent setpoint drift. The capability of

the Unit 1 and Unit 2 HPCI and RCIC systems to deliver design flows

at these pressures was reviewed by GE and is discussed in Reference

2.

iii. The peak post accident containment pressure (Pa) is

changed to 49.6 psig (Unit 1) and 45.5 psig (Unit 2). These values

appear in Units 1 and 2 Bases Sections B 3.6.1.1, B 3.6.1.2, and B

3.6.1.4.

Section 4.1.1.3 of NEDC-32405P discusses the peak short-term

containment pressure response which was recalculated for power

uprate conditions. Containment pressure and temperatures remain

below design limits and are essentially unchanged.

iv. The main condenser offgas gross gamma activity rate limit of

240 mci/second will not be changed for power uprate. A statement

that the current limit is conservative for power uprate conditions

was added to Units 1 and 2 Bases Section 3.7.6.

The Bases derive the current 240 mci/second limit using a rated

core thermal power limit of 2436 MWt. A slightly higher limit could

be justified using the uprated power level. However, adequate margin

exists with the current limit.

v. The inservice hydrostatic and leak testing pressures shown in

Units 1 and 2 Bases Section 3.10.1 are increased 33 psi and 30 psi,

respectively.

This change is a direct result of the 30 psi increase in normal

operating pressure proposed for power uprate. The leakage test is

normally performed at operating pressure and the hydrostatic test at

approximately 110 percent of operating pressure.

The above Bases changes i-v were evaluated, and there is no

significant decrease 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 10 CFR 50.92(c) are

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Appling County Public Library,

301 City Hall Drive, Baxley, Georgia 31513.

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

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

20037.

NRC Project Director: Herbert N. Berkow.

Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric

Authority of Georgia, City of Dalton, Georgia, Docket No. 50-366, Edwin

I. Hatch Nuclear Plant, Unit 2, Appling County, Georgia

Date of amendment request: April 14, 1995.

Description of amendment request: The licensee proposes to revise

Plant Hatch Unit 2 Technical Specifications (TS) to eliminate selected

response time testing requirements from the TS. Specifically, the

response time testing to be eliminated includes sensors and specified

loop instrumentation for: (1) the Reactor Protection System, (2) the

Isolation System, and (3) the Emergency Core Cooling System (ECCS). The

deletion of instrumentation from the ECCS response time testing

necessitates moving the remaining portion of the test to the ECCS

system TS. In addition, the Note for Surveillance Requirement

3.3.6.1.7, which reads: ``Radiation detectors may be excluded,'' is

being removed since response time testing is not required for any

radiation detector that provides a primary containment isolation signal

as indicated in Table 3.3.6.1-1.

Proposed TS Changes 1, 2, and 3 are supported by an analysis

performed by the BWR Owners' Group (BWROG), with the licensee's

participation. The analysis was submitted to the NRC for approval as

Topical Report NEDO-32291, ``System Analyses for the Elimination of

Selected Response Time Testing Requirements,'' Boiling Water Reactor

Owners' Group, January 1994. The NRC approved the Topical Report by a

Safety Evaluation Report (SER) issued on December 28, 1994,

``Evaluation of Boiling Water Reactor Owners' Group Topical Report

NEDO-32291, System Analyses for the Elimination of Selected Response

Time Testing Requirements.'' The BWROG analysis demonstrates that other

periodic tests required by TS, such as channel calibrations, channel

checks, channel functional tests, and logic system functional tests,

ensure that instrument response times are within acceptable limits. The

applicability of the referenced analysis to Plant Hatch has been

verified. Proposed Change 4 removes an unnecessary note, since no

functions subject to this surveillance include radiation monitors.

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:

Basis for Proposed Changes 1, 2, and 3

1. The changes do not involve a significant increase in the

probability or consequences of an accident previously evaluated. The

purpose of the proposed changes is to eliminate response time

testing requirements for selected instrumentation in the RPS

[Reactor Protection System], Isolation System], and ECCS. However,

because of the continued application of other existing Technical

Specifications requirements, such as channel calibrations, channel

checks, channel functional tests, and logic system functional tests,

the response time of these systems will be maintained within the

acceptance limits assumed in plant safety analyses. This will assure

successful mitigation of an initiating event. The proposed Technical

Specifications changes do not affect the capability of the

associated systems to perform their intended function within their

required response time.

The BWR Owners' Group (BWROG) has documented an evaluation in

NEDO-32291, ``System Analyses for Elimination of Selected Response

Time Testing Requirements,'' which was submitted to the NRC for

review and approval as a Topical Report in January 1994 and

subsequently approved by an NRC SER in December 1994. This

evaluation demonstrates that response time testing is redundant to

the other Technical Specifications requirements listed in the

preceding paragraph. These other tests are sufficient to identify

failure modes or degradation in instrument response time and ensure

operation of the associated systems within acceptance limits. There

are no known failure modes that can be detected by response time

testing that cannot also be detected by the other Technical

Specifications tests.

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

or different kind of accident from any accident previously analyzed.

As discussed above, the proposed Technical Specifications changes do

not affect the capability of the associated systems to perform their

intended function within the acceptance limits assumed in plant

safety analyses.

3. The proposed changes do not involve a significant reduction

in the margin of safety. The current Technical Specifications

response times are based on the maximum allowable values assumed in

the plant safety

[[Page 35077]]

analyses, which conservatively establish the margin of safety. As

described above, the proposed Technical Specifications changes do

not affect the capability of the associated systems to perform their

intended function within the allowed response time used as the basis

for the plant safety analyses. Plant and system responses to an

initiating event will remain in compliance with the assumptions of

the safety analyses; therefore, the margin of safety is not

affected.

Although not explicitly evaluated, the proposed Technical

Specifications changes enhance plant safety and operation by:

a. Reducing the time safety systems are unavailable,

b. Reducing safety system actuations,

c. Reducing shutdown risk,

d. Limiting radiation exposure to plant personnel, and

e. Eliminating the diversion of key personnel to conduct

unnecessary testing.

Basis for Proposed Change 4

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

probability or consequences of an accident previously evaluated. The

Note for SR 3.3.6.1.7 indicates that response time testing for

radiation detectors that provide primary containment isolation

signals as indicated in Table 3.3.6.1-1 is not required. However,

Table 3.3.6.1-1 does not reference SR 3.3.5.1.7 for any

radiation detector that provides primary containment isolation

signals. The proposed change eliminates the potential for confusion

during instrumentation surveillance testing. Deletion of the note

will not prevent the radiation detectors from performing their

intended function and will not affect the results of any accident

analysis.

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

or different kind of accident from any accident previously analyzed.

As discussed above, the proposed Technical Specifications change

eliminates the potential for confusion during instrumentation

surveillance testing. This change does not modify any plant

equipment or change any plant procedure that provides instructions

for the operation of plant equipment. Therefore, the proposed change

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

accident from any previously analyzed.

3. The proposed change does not involve a significant reduction

in the margin of safety. The Note that is being deleted by the

change states that testing is not required for instrument sensors

which is not required by the SR. Therefore, the Note is superfluous

and could cause confusion during instrumentation surveillance

testing. The proposed change eliminates that potential. This change

is conservative, since it deletes a statement that was intended to

reduce the amount of surveillance testing performed on certain

instrumentation. The proposed change does not affect plant

equipment, procedures, or radiation release prevention and

mitigating functions. 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 10 CFR 50.92(c) are

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Appling County Public Library,

301 City Hall Drive, Baxley, Georgia 31513.

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: March 17, 1995.

Description of amendment request: The amendments would revise

Technical Specification (TS) 3.9.4, Containment Building Penetrations,

to allow the personnel airlock to be open during core alterations or

movement of irradiated fuel within the containment.

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 change to the Technical Specifications does not

involve a significant increase in the probability or consequences of

an accident previously evaluated. The proposed change to

Specification 3.9.4 would allow the containment personnel airlock

(PAL) to be open during fuel movement and core alterations. The PAL

is currently closed during fuel movement and core alterations to

prevent the escape of radioactive material in the event of a fuel

handling accident. The PAL is not an initiator to any accident.

Whether the PAL doors are opened or closed during fuel movement or

core alterations has no effect on the probability of any accident

previously evaluated.

Allowing the PAL doors to be open during fuel movement and core

alterations does increase the consequences of a fuel handling

accident in the containment from essentially no offsite dose release

to an estimated release of 65.6 rem to the thyroid and 0.28 rem to

the whole body. However, the calculated offsite dose release is

lower than the case analyzed in the FSAR [Final Safety Analysis

Report] for an accident in the Spent Fuel Pool, with no filtration

of the resulting release. In addition, the calculated doses are

larger than the expected doses because the calculation does not

incorporate the closing of the PAL door after the containment is

evacuated. Closing the airlock door within 15 minutes results in a

calculated offsite dose of 8.2 rem to the thyroid and 0.025 rem

whole body. The projected dose to control room operators was

reviewed and the projected dose remained below SRP acceptance limits

as long as control room emergency ventilation was established within

7 minutes. It was assumed the individual assigned to close the

airlock doors remained stationed at the airlock for 15 minutes. A

best estimate dose analysis indicated this individual could be

expected to receive 5.6 rem to the thyroid and 0.15 rem whole body.

The proposed change will significantly reduce the dose to other

workers in the containment in the event of a fuel handling accident

by speeding the containment evacuation process. The proposed change

will also significantly decrease the wear on the PAL doors and,

consequently, increase the availability of the PAL doors in the

event of an accident.

Therefore, the proposed change does not involve a significant

increase in the probability or consequences of an accident

previously evaluated.

2. The proposed change to the Technical Specifications does not

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

any accident previously evaluated because the proposed change

affects a previously evaluated accident, e.g., a fuel handling

accident. It does not represent a significant change in the

configuration or operation of the plant and, therefore, does not

create the possibility of a new or different type of accident from

any accident previously evaluated.

3. The proposed change to the Technical Specifications does not

involve a significant reduction in a margin of safety. The margin of

safety as defined by 10 CFR Part 100 for a fission product release

is 300 rem thyroid and 25 rem whole body for an individual exposed

at the site boundary for two hours. The analysis shows values that

are well below the acceptance limits. In fact, the margin remains

essentially the same as previously evaluated by the NRC. There is no

increase in calculated offsite dose resulting from a fuel handling

accident. Therefore, the proposed change does not involve a

significant reduction in a margin of safety.

Based upon the preceding information, it has been determined

that the proposed Technical Specifications addition does 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 location: 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.

[[Page 35078]]

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: May 12, 1995.

Description of amendment request: The proposed amendments would

revise the Technical Specifications (TS) to support a one-time

exemption from the requirement of Section III.D.1(a) of 10 CFR Part 50,

Appendix J, and any other future Appendix J exemptions that may be

approved by the NRC for Vogtle, Unit 1. Specifically, the TS change

would insert the words ``Except as modified by NRC approved

exemptions'' at the beginning of the first sentence of TS Surveillance

Requirement 4.6.1.2.

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 change does not involve a significant increase in the

probability or consequences of an accident previously evaluated. The

proposed change does not involve a change to structures, systems, or

components which would affect the probability of an accident

previously evaluated in the Vogtle Electric Generating Plant (VEGP)

Final Safety Analysis Report (FSAR). The change only provides a

mechanism for implementing exemptions to 10 CFR 50, Appendix J

containment leak rate testing criteria which have been approved by

the NRC.

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

or different kind of accident from any accident previously analyzed.

The amendment would not change the design, configuration, or method

of plant operation. It only allows exemption to specific 10 CFR 50,

Appendix J criteria as previously approved by the NRC.

3. Operation of VEGP, Unit 1 in accordance with the proposed

change will not involve a significant reduction in the margin of

safety. The proposed change would not, in itself, change a safety

limit, an LCO, or a surveillance requirement on equipment required

for plant operation. Before the change could be used an exemption to

10 CFR 50, Appendix J would have to be evaluated and approved by the

NRC. The change only provides a way to implement NRC approved

exemptions without violating the Technical Specifications.

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

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

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Burke County Public Library,

412 Fourth Street, Waynesboro, Georgia 30830.

GPU Nuclear Corporation, et al., Docket No. 50-289, Three Mile Island

Nuclear Station, Unit No. 1, Dauphin County, Pennsylvania

Date of amendment request: June 1, 1995.

Description of amendment request: The proposed license amendment

would revise the Technical Specifications (T.S.) for Three Mile Island

Nuclear Station, Unit 1 (TMI-1) to delete the remaining portions of the

TMI-1 Radiological Effluent Technical Specifications (RETS) and

relocate them in accordance with the guidance contained in the Generic

Letter 89-01 (GL 89-01) and NUREG-1430. The proposed change would also

modify the Radiation Monitoring Systems surveillance requirements to

specify only those radiation monitors that have Limiting Conditions for

Operation (LCO), and revise some of the calibration frequencies.

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 the facility in accordance with the proposed

amendment would not involve a significant increase in the

probability of occurrence or the consequences of an accident

previously evaluated. The proposed amendment allows relocation of

the remaining RETS to the ODCM [Offsite Dose Calculation Manual]

according to the guidance contained in GL 89-01 and NUREG-1430. This

proposal simplifies the RETS, meets the regulatory requirements for

radioactive effluent controls and radiological environmental

monitoring, and is provided as a line-item improvement of the T.S.

In addition, this proposed amendment specifies surveillance

requirements only for those radiation monitors that have an LCO or

specified operability requirements. The radiation monitors that are

currently included in the T.S. surveillance program but have no

associated LCO or specified operability requirement will be placed

in the PM [preventive maintenance] program.

Finally, the proposed amendment extends the interval between

successive calibration surveillances for those radiation monitors

evaluated herein. This change does not involve any change to the

actual surveillance requirements, nor does it involve any change to

the limits or restrictions on plant operations. The reliability of

systems and components relied upon to prevent or mitigate the

consequences of accidents previously evaluated is not degraded

beyond that obtained from the currently defined quarterly interval.

Assurance of system and equipment availability is maintained.

This change does not involve any change to system or equipment

configuration. Therefore, this change does not significantly

increase the probability of occurrence or the consequences of an

accident previously evaluated.

2. Operation of the facility in accordance with the proposed

amendment would not create the possibility of a new or different

kind of accident from any accident previously evaluated.

The proposal in part relocates procedural details, currently

included in the T.S., on radioactive effluents to the ODCM. Future

changes to these procedural details in the ODCM will be handled

under the administrative controls for changes to the ODCM.

In addition, this proposed amendment specifies surveillance

requirements only for those radiation monitors that have an LCO or

specified operability requirements. The radiation monitors that are

currently included in the T.S. surveillance program but have no

associated LCO or specified operability requirement will be placed

in the PM program.

Finally, the proposed amendment extends the interval between

successive calibration surveillances for those radiation monitors

evaluated herein. This change does not involve any change to the

actual surveillance requirements, nor does it involve any change to

the limits and restrictions on plant operations. This change does

not involve any change to system or equipment configuration.

Therefore, this change is unrelated to the possibility of

creating a new or different kind of accident from any previously

evaluated.

3. Operation of the facility in accordance with the proposed

amendment would not involve a significant reduction in a margin of

safety.

The procedural details being relocated to the ODCM are

consistent with the guidance provided in GL 89-01 and NUREG-1430.

In addition, this proposed amendment specifies surveillance

requirements only for those radiation monitors that have an LCO or

specified operability requirements. The radiation monitors that are

currently included in the T.S. surveillance program but have no

associated LCO or specified operability requirement will be placed

in the PM program.

Finally, the proposed amendment extends the interval between

successive calibration surveillances for those radiation monitors

evaluated herein. This change does not involve any change to the

actual surveillance requirements, nor does it involve any change to

the limits and restrictions on plant operations. The reliability of

the radiation monitors is not significantly degraded beyond that

obtained from the currently defined surveillance interval. Assurance

of system availability is maintained.

Therefore, it is concluded that operation of the facility in

accordance with the proposed amendment does not involve a

significant reduction in a margin of safety.

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

this

[[Page 35079]]

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

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Law/Government Publications

Section, State Library of Pennsylvania, (REGIONAL DEPOSITORY) Walnut

Street and Commonwealth Avenue, Box 1601, Harrisburg, PA 17105.

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

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

NRC Project Director: Phillip F. McKee.

Gulf States Utilities Company, Cajun Electric Power Cooperative, and

Entergy Operations, Inc., Docket No. 50-458, River Bend Station, Unit

1, West Feliciana Parish, Louisiana

Date of amendment request: May 30, 1995.

Description of amendment request: The proposed amendment would

revise the technical specifications (TS) to increase the surveillance

test period for the containment integrated leak rate test (ILRT) from

40 plus or minus 10 months to every 10 years based on past performance.

The change would also require testing on a more frequent basis if any

test failures were to occur and to return to the 10 year period with

subsequent performance improvements.

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 change does not involve a change to the plant

design or operation. As a result, the proposed change does not

affect any of the parameters or conditions that contribute to

initiation of any accidents previously evaluated. Thus, the proposed

change cannot increase the probability of any accident previously

evaluated. The proposed change potentially affects the leak tight

integrity of the containment structure designed to mitigate the

consequences of a loss of coolant accident (LOCA). The function of

the containment is to maintain functional integrity during and

following the peak transient pressures and temperatures which result

from any loss of coolant accident (LOCA). The containment is

designed to limit fission product leakage following the design basis

LOCA and analyses demonstrate that these offsite doses are less than

those allowed under 10CFR100 design limits of 15 psig and 185

deg.F. Because the proposed change does not alter the plant design,

only the frequency of measuring containment leakage, the proposed

change does not directly result in an increase in containment

leakage. However, decreasing the test frequency can increase the

probability that a large increase in containment leakage could go

undetected for an extended period of time. These leakage paths

include potential cracks in the containment structure and various

penetrations through the containment structure. Based upon the

results of the structural integrity test conducted as part of the

preoperational or preservice test program and the periodic

containment and drywell structural integrity surveillance tests,

additional cracking of the containment is not expected during the

remaining life to the plant. Ventilation and piping penetrations are

designed with two isolation valves in series with one valve in the

drywell and another either outside primary containment or in the

wetwell. High energy lines that extend into the wetwell, such as the

Main Steam and Feedwater lines, are encapsulated by guard pipes to

direct energy to the drywell in case of a piping rupture.

Electrical penetrations are sealed with a high strength/density

material that will prevent leakage as well as provide radiation

shielding. The TS ILRT acceptance criterion of 0.75 La [maximum

allowable leakage rate at the calculated maximum accident pressure,

Pa] provides margin for degradation. Containment performance

data to date suggests that containment degradation, even during a

ten (10) year interval between tests, will not exceed this margin.

Based on the above, EOI [Entergy Operations, Inc.] has concluded

that the proposed change will not result in a significant increase

in the probability or consequences of any accident previously

evaluated.

(2) The proposed change does not involve a change to the plant

design or operation. As a result, the proposed change does not

affect any of the parameters or conditions that could contribute to

initiation of any accidents. This change involves the reduction in

the Integrated Leak Rate Test frequency. The method of performing

the test is not changed. No new accident modes are created by

extending the testing intervals. No safety-related equipment or

safety functions are altered as a result of this change. Extending

the test frequency has no influence on, nor does it contribute to,

the possibility of a new or different kind of accident or

malfunction from those previously analyzed. Based upon the above,

EOI has concluded that the proposed change will not create the

possibility or a new or different kind of accident previously

evaluated.

(3) The proposed change only affects the frequency of measuring

containment leakage and does not change the leakage rate limit.

However, the proposed change can increase the probability that a

large increase in containment leakage could go undetected for an

extended period of time. Operational experience has shown that the

leak tightness of the containment has been maintained significantly

below the allowable leakage limit. In fact, an analysis was

conducted to determine the potential risk to the public from the

proposed change. Based on this analysis, under several different

accident scenarios, the risk of radioactivity release from

containment was found to be negligible.

The margin of safety that has the potential of being impacted by

the proposed change involves the offsite dose consequences of

postulated accidents which are directly related to containment

leakage rate. The containment isolation system is designed to limit

leakage to La which is defined by the RBS Technical

Specifications to be 0.26 percent by weight of the containment air

per 24 hours at 7.6 psig (Pa). The limitation on containment

leakage rate is designed to ensure that total leakage volume will

not exceed the value assumed in the accident analyses at the peak

accident pressure (Pa) or 7.6 psig.

To provide additional conservatism, the measured overall

integrated leakage rate is further limited to less than or equal to

0.75 La during performance of the periodic Integrated Leak Rate

Test and to less than or equal to 0.60 La (total combined

leakage) for Type B and C leak rate tests. This is done to account

for the possible degradation of the containment leakage barriers

between tests. These acceptance criteria ensure that an acceptable

margin of safety is being maintained and will not be altered by the

proposed change. The preservation of this margin will continue to

provide for potential degradation of the leakage barriers between

tests. RBS [River Bend Station] presently has on docket with the

staff a submittal (reference RBG-41133, Rev. 1 to LAR 93-14 dated

January 18, 1995) that allows the acceptance criteria, between

required leakage rate tests, to be less than or equal to 1.0 La

since at less than or equal to 1.0 La, the offsite does

consequences are bounded by the assumptions of safety analysis.

No change in the method of testing is being proposed. The Type A

test will continue to be done at full pressure (Pa) or greater.

Primary containment penetrations which require Type B or C leak

tests will be performed in the same manner as before. Other programs

are in place to ensure that proper maintenance and repairs are

performed during the service life of the primary containment and

systems and components penetrating the primary containment.

No change in the RBS allowable leakage rate is being proposed.

These conservative leakage rates ensure that the containment leakage

remains low. As a result, EOI has concluded that the proposed change

will not result in 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 10 CFR 50.92(c) are

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Government Documents

Department, Louisiana State University, Baton Rouge, Louisiana 70803.

Attorney for licensee: Mark Wetterhahn, Esq., Winston & Strawn,

[[Page 35080]]

1400 L Street, N.W., Washington, DC 20005.

NRC Project Director: William D. Beckner.

Gulf States Utilities Company, Cajun Electric Power Cooperative, and

Entergy Operations, Inc., Docket No. 50-458, River Bend Station, Unit

1, West Feliciana Parish, Louisiana

Date of amendment request: May 30, 1995.

Description of amendment request: The proposed amendment would

revise the technical specifications (TS) to increase the time period

for drywell leakage tests from eighteen months to five years based on

performance. The new surveillance requirements would also reduce the

time period if any failures occur and limit subsequent periods until

drywell leakage test performance again improves.

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 change does not involve a change to the plant

design or operation. As a result, the proposed change does not

affect any of the parameters or conditions that contribute to

initiation of any accidents previously evaluated. Thus, the proposed

change cannot increase the probability of any accident previously

evaluated.

The proposed change potentially affects the leak tight integrity

of the drywell, a structure used to mitigate the consequences of a

loss of coolant accident (LOCA). The function of the drywell is to

channel the steam released from a LOCA through the suppression pool,

limiting the amount of steam released to the primary containment

atmosphere. This limits the containment pressurizations due to the

LOCA. The leakage of the drywell is limited to ensure that the

primary containment does not exceed its design limits of 185 deg.F

and 15 psig. Because the proposed change does not alter the plant

design, only the frequency of measuring the drywell leakage, the

proposed change does not directly result in an increase in drywell

leakage. However, decreasing the test frequency can increase the

probability that a large increase in drywell bypass leakage could go

undetected for an extended period of time. There are several

potential sources of steam bypass leakage paths. These include

potential cracks in the drywell concrete structure and various

penetrations through the drywell structure. Based upon the results

of the structural integrity test conducted as part of the

preoperational or preservice test program, additional cracking of

the drywell is not expected during the remaining life of the plant.

Ventilation and piping penetrations are designed with two isolation

valves in series with one valve in the drywell and another either

outside primary containment or in the wetwell. High energy lines

that extend into the wetwell, such as the Main Steam line and

Feedwater lines, are encapsulated by guard pipe to direct energy to

the drywell in case of a piping rupture. Electrical penetrations are

sealed with a high strength/density material that will prevent

leakage as well a provide radiation shielding. The TS DBLRT [Drywell

Bypass Leakage Rate Tests] acceptance criterion of 10% of the design

bypass leakage area parameter provides margin for degradation.

Drywell performance data to date suggests that drywell degradation,

even during a five year interval between tests, will not exceed this

margin. RBS presently has on docket with the staff a submittal

(reference EOI letter RBG-41133, Rev. 1 to LAR 93-14 dated January

18, 1995) that allows the acceptance criteria, between required

leakage rate tests, to be (bypass leakage area parameter) since at

(bypass leakage area parameter) the containment temperature and

pressurization response are bounded by the assumptions of the safety

analysis.

Based on the above, EOI has concluded that the proposed change

will not result in a significant increase in the consequences of any

accident previously evaluated.

(2) The proposed change does not involve a change to the plant

design or operation. As a result, the proposed change does not

affect any of the parameters or conditions that could contribute to

initiation of any accidents. Thus, the proposed change cannot create

the possibility of an accident not previously evaluated.

(3) The proposed change only affects the frequency of measuring

the drywell bypass leakage rate and does not change the bypass

leakage limit for the drywell. However, the proposed change can

increase the probability that a large increase in drywell bypass

leakage could go undetected for an extended period of time.

Operational experience has shown that the leak tightness of the

drywell has been maintained significantly below the allowable

leakage limits. In fact, an analysis was conducted to determine the

potential risk to the public from the proposed change. Based on this

analysis, under several different accident scenarios, the risk of

radioactivity release from containment was found to be negligible.

As a result, EOI has concluded that the proposed change will not

result in 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 10 CFR 50.92(c) are

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

amendment request involves no significant hazards consideration.

Local Public Document Room location: Government Documents

Department, Louisiana State University, Baton Rouge, Louisiana 70803.

Attorney for licensee: Mark Wetterhahn, Esq., Winston & Strawn,

1400 L Street, N.W., Washington, D.C. 20005.

NRC Project Director: William D. Beckner.

Indiana Michigan Power Company, Docket Nos. 50-315 and 50-316, Donald

C. Cook Nuclear Plant, Unit Nos. 1 and 2, Berrien County, Michigan

Date of amendment requests: May 25, 1995 (AEP:NRC:107IT).

Description of amendment requests: The proposed amendments would

implement a cycle- and burnup-dependent peaking factor penalty to the

allowable power level. The Technical Specifications would be changed to

refer to the Core Operating Limits Report for this burnup-dependent

penalty.

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:

Per 10 CFR 50.92, a proposed amendment will not involve a

significant hazards consideration if the proposed amendment does

not:

(1) involve a significant increase in the probability or

consequences of an accident previously evaluated,

(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.

Criterion 1

The proposed changes will not involve a significant increase in

the probability of an accident previously evaluated because the

changes will not result in a change to any of the process variables

that might initiate an accident. There are no physical changes to

the plant associated with this T/S change. The consequences of an

accident previously evaluated will not be increased because the

changes increase the penalty applied to FQ when it is measured

to be increasing. FQ and allowable power level (APL) T/S

surveillance requirements are not being changed. Furthermore,

allowing a cycle and burnup dependent FQ penalty to be located

in the COLR was accepted by the NRC in a [November 26, 1993] safety

evaluation on WCAP-10216-P, Rev. 1 [``Relaxation of Constant Axial

Offset Control- FQ Surveillance Technical Specification''].

Criterion 2

The proposed changes will not create the possibility of a new or

different kind of accident from any accident previously evaluated

because the changes will involve no physic

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