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

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URL: https://www.frixlaw.com/law-library/documents/fr%3A95-16249

## Record

- **Collection:** Federal Register
- **Document type:** Notice
- **Published:** July 5, 1995
- **Citation:** 60 FR 35058

## Text

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

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A95-16249. Public record. Not legal advice.