ML20101P987

Amend 171 to License DPR-20,modifying Plant FOL to Reference 10CFR40,allowing Use of Source Matls as Reactor Fuel,Deletes References to Specific Amend & Specific Revisions in Listed Titles of PSP & Suitability Training & Qualification Plan

ML20101P987
Person / Time
Site:	Palisades
Issue date:	04/05/1996
From:	Kennedy J NRC (Affiliation Not Assigned)
To:
Shared Package
ML20101P994	List: ML20101P987 ML20101P995 ML20101Q004
References
NUDOCS 9604100117
Download: ML20101P987 (45)

Text

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[w UNITED STATES j

j NUCLEAR REGULATORY COMMISSION l'

WASHINGTON. D.C. 20666 4 001 49 *****

CONSUMERS POWER COMPANY l

DOCKET NO. 50-255 l

PALISADES PLANT AMENDMENT TO FACILITY OPERATING LICENSE l

Amendment No.171 License No. DPR-20 1.

The Nuclear Regulatory Commission (the Comission) has found that:

A.

The application for amendment by Consumers Power Company (the licensee) dated October 17, 1995, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act),

3 and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; i

C.

There is reasonable assurance (1) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public; and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to the license amendment and Facility Operating License No. DPR-20 is hereby amended to read as follows:

1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for a license filed by Consumers Power Company (CPCo) complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and 10 CFR Chapter I, and all required notifications to other agencies or bodies have i

been duly made; 9604100117 960405 PDR ADOCK 05000255 P,

PDR

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l 2

B.

Construction of the Palisades Plant (the facility) has been completed in conformity with Provisional Construction Permit No.

CPPR-25 and the application, as amended, the provisions of the Act, and the regulations of the Commission, and has been operating i

under a provisional operating license since March 24, 1971; I

C.

The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission (except as exempted from compliance in Section 4

l 2.D. below),

D.

There is reasonable assurance that the activities authorized by

)

this Facility Operating License can be conducted without endangering the health and safety of the public; E.

CPCo is technically qualified to engage in the activities authorized by this license, as amended, in accordance with 10 CFR Chapter I; F.

CPCo has satisfied the applicable provisions of 10 CFR Part 140, l

" Financial Protection Requirements and Indemnity Agreements";

i 1

5 G.

The issuance of this license will not be inimical to the common j

defense and security or to the health and safety of the public; M.

The issuance of this license is in accordance with 10 CFR Part 51 and all applicable requirements have been satisfied; and 4

I.

The receipt, possession, and use of source, byproduct, and special 4

nuclear material as authorized by this license will be in accordance with 10 CFR Parts 30, 40, and 70.

2.

Provisional Operating License No. DPR-20, dated March 24, 1971 as amended, is superseded in its entirety by Facility Operating License No. DPR-20 hereby issued to Consumers Power Company (CPCo) to read as follows:

~

A.

This license applies to the Palisades Plant, a pressurized light water moderated and cooled reactor and electrical generating equipment (the facility). The facility is located in Van Buren County, Michigan, and is described in CPCo's Updated Final Safety Analysis Report, as supplemented and amended, and in CPCo's Environmental Report, as supplemented and amended.

B.

Subject to the conditions and requirements incorporated herein, the Commission hereby licenses:

4 Q

3 (1) CPCo, pursuant to Section 104b of the Atnmic Energy Act of 1954, as amended, and 10 CFR Part 50, " Domestic Licensing of Production and Utilization Facilities," to possess, use, and operate the facility in accordance with the limitations set forth in this license; (2) CPCo, pursuant to the Act and 10 CFR Parts 40 and 70, to receive, possess, and use source and special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Updated Final Safety Analysis Report, as supplemented and amended; (3) CPCo, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive possess, and use byproduct, source, and special nuclear material as sealed sources for reactor startup, reactor instrumentation, radiation monitoring equipment calibration, and fission detectors in amounts as required; (4) CPCo, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive, possess, and use in amounts as required any byproduct, source, or special nuclear material for sample analysis or instrument calibration, or associated with radioactive apparatus or components; and (5) CPCo, pursuant to the'Act and 10 CFR Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operations of the facility.

C.

This license shall be deemed to contain and is subject to all applicable provisions of the Act; to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) CPCo is authorized to operate the facility at steady-state reactor core power levels not in excess of 2530 Megawatts thermal (100 percent rated power) in accordance with the conditions specified herein.

(2) The Technical Specifications contained in Appendix A, as revised through Amendment No.171, and the Environmental Protection Plan contained in Appendix B are hereby incorporated in the license. CPCo shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

(3) CPCo shall implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report for the facility and as approved in the

4 SERs dated 09/01/78, 03/19/80, 02/10/81, 05/26/83, 07/12/85, 01/29/86, 12/03/87, and 05/19/89 and subject to the following provisions:

a.

CPCo may make changes to the approved fire protection program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

b.

CPCo may alter specific features of the approved fire protection program provided:

Such changes do not result in failure to complete the fire protection program as approved by the Commission.

CPCo shall maintain in auditable form, a current

.l record of all such changes, including an analysis of the effects of the change on the fire protection program and shall make such records available to the Commission Inspectors upon request. All changes to the approved program shall be reported annually, along with the FSAR revision; and Temporary changes to specific fire protection features which may be necessary to accomplish maintenance or modifications are acceptable provided interim i

compensatory measures are implemented.

D.

The facility has been granted certain exemptions from the requirements of Section III.G of Appendix R to 10 CFR Part 50,

" Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1, 1979." This section relates to fire protection features for ensuring the systems and associated circuits used to achieve and maintain safe shutdown are free of fire damage. These exemptions were granted and sent to CPCo in letters dated February 8,1983, July 12,1985, and July 23, 1985.

In addition, the facility has been granted certain exemptions from Appendix J to 10 CFR Part 50, " Primary Reactor Containment Leakage Testing for Water Cooled Power Reactors." This section contains leakage test requirements, schedules and acceptance criteria for tests of the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment. These exemptions were granted and sent to CPCo in a letter dated December 6,1989.

These exemptions granted pursuant to 10 CFR 50.12, are authorized by law, will not present an undue risk to the public health and safety, and are consistent with the common defense and security.

With these exemptions, the facility will operate, to the extent

5 authorized herein, in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission.

E.

CPCo shall fully implement and maintain in effect all provisions of the Commission-approved " Palisades Plant Physical Security Plan," " Palisades Plant Suitability Training and Qualification 4

Plan," and " Palisades Plant Safeguards Contingency Plan," and all approved amendments. CPCo may make changes to these plans without prior Commission approval, if the changes do not decrease the safeguards effectiveness of the plans, in accordance with 10 CFR 50.54(p)(2).

F.

Except as otherwise provided in the Technical Specifications or Environmental Protection Plan, the licensee shall report any violations of the requirements contained in Section 2.C of this license in the following manner:

initial notification shall be

)

made within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to the NRC Operations Center via the Emergency Notification System with written follow-up within 30 days in accordance with the procedures described in 10 CFR 50.73(b), (c), and (e).

G.

CPCo shall have and maintain financial protection of such type and in such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims.

H.

This license is effective as of the date of issuance and shall expire at midnight on March 14, 2007.

3.

This license amendment is effective as of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Jw %

Janet Kennedy, Project Manager Project Directorate 111-1 Division of Reactor Projects - III/IV Office of Nuclear Reactor Regulation Attachments:

(1) Pages 1-4 of License IIo. DPR-20*

(2) Changes to the Technical Specifications Date of Issuance:

April 5, 1996 Pages 1-4 are attached, for convenience, for the composite license to reflect these changes.

ATTACHMENT TO LICENSE AMENDMENT NO.171 FACILITY OPERATING LICENSE NO. DPR-20 DOCKET NO. 50-255 LICENSE REMOVE INSERT Pages 1 Pages 1 2

2 3

3 4

4 5

TECHNICAL SPECIFICATIONS Revise Appendix A Technical Specifications by removing the pages identified below and inserting the attached pages. The revised pages are identified by amendment number and contain vertical lines indicating the areas of change.

REMOVE INSERT 3-2 3-2 3-3 3-3 3-4 3-4 3-7 3-7 3-30 3-30 3-31 3-31 3-42 3-42 3-56 3-56 3-62 3-62 B 3.16-2 B 3.16-2 B 3.17-3 B 3.17-3 B 3.17-25 B 3.17-25 B 3.17-26 B 3.17-26 B 3.17-27 B 3.17-27 B 3.17-28 8 3.17-28 B 3.17-29 B 3.17-29 B 3.17-30 B 3.17-30 B 3.17-31 B 3.17-31 B 3.17-32 B 3.17-32 8 3.17-33 B 3.17-33 8 3.17-34 B 3.17-34 4-1 4-1 4-3 4-3 4-6 4-6 4-69 4-69 4-72 4-72 4-73 4-73 4-76 4-76 4-77 4-77 4-78 4-78 4-79 4-79 4-80 4-80 4-81 4-81 4-82 4-82 5-3 5-3

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'a UNITED STATES l

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NUCLEAR REGULATORY COMMISSION t

WASHINGTON, D.C. enmas aang

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CONSUMERS POWER COMPANY l

DOCKET NO. 50-255 PALISADES PLANT FACILITY OPERATING LICENSE License No. DPR-20 1.

The Nuclear Regulatory Commission (the Commission) has found that:

l A.

The application for a license filed by Consumers Power Company (CPCo) l complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and 10 CFR Chapter I, and all required l

notifications to other agencies or bodies have been duly made; B.

Construction of the Palisades Plant (the facility) has been completed in conformity with Provisional Construction Permit No. CPPR-25 and the application, as amended, the provisions of the Act, and the regulations of the Commission, and has been operating under a provisional operating license since March 24, 1971; C.

The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission (except as exempted from compliance in Section 2.D.

below)-

D.

There is reasonable assurance that the activities authorized by this Facility Operating License can be conducted without endangering the health and safety of the public; E.

CPCo is technically qualified to engage in the activities authorized by this license, as amended, in accordance with 10 CFR Chapter I; F.

CPCo has satisfied the applicable provisions of 10 CFR Part 140,

" Financial Protection Requirements and Indemnity Agreements";

G.

The issuance of this license will not be inimical t'o the common defense and security or to the health and safety of the public; H.

The issuance of this license is in accordance with 10 CFR Part 51 and l

all applicable requirements have been satisfied; and I.

The receipt, possession, and use of source, byproduct, and special l

nuclear material as authorized by this license will be in accordance with 10 CFR Parts 30, 40, and 70.

l 2.

Provisional Operating License No. DPR-20, dated March 24, 1971 as amended, is superseded in its entirety by Facility Operating License No. DPR-20 hereby issued to Consumers Power Company (CPCo) to read as follows:

l Amendment No.171

i 2

A.

This license applies to the Palisades Plant, a pressurized light water moderated and cooled reactor and electrical generating equipment (the facility). The facility is located in Van Buren County, Michigan, and is described in CPCo's Updated Final Safety Analysis Report, as supplemented and amended, and in CPCo's Environmental Report, as supplemented and amended.

B.

Subject to the conditions and requirements incorporated herein, the Comission hereby licenses:

)

(1) CPCo, pursuant to Section 104b of the Atomic Energy Act of 1954, as amended, and 10 CFR Part 50, " Domestic Licensing of Production and Utilization Facilities," to possess, use, and operate the facility in accordance with the limitations set forth in this license; (2) CPCo, pursuant to the Act and 10 CFR Parts 40 and 70, to receive, possess, and use source and special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Updated Final Safety Analysis Report, as supplemented and amended; (3) CPCo, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive possess, and use byproduct, source, and special nuclear material as sealed sources for reactor startup, reactor instrumentation, radiation monitoring equipment calibration, and fission detectors in amounts as required; (4) CPCo, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive, possess, and use in amounts as required any byproduct, source, or special nuclear material for sample analysis or instrument calibration, or associated with radioactive apparatus or components; and (5) CPCo, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to l

possess, but not separate, such byproduct and special nuclear materials as may be produced by the operations of the facility.

C.

This license shall be deemed to contain and is subject to all applicable provisions of the Act; to the rules, regulations, and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1)CPCoisauthorizedtooperatethefacilityatsteady-statereactorl core power levels not in excess of 2530 Megawatts thermal (100 percent rated power) in accordance with the conditions specified herein.

(2) The Technical Specifications contained in Appendix A, as revised l

through Amendment No.171, and the Environmental Protection Plan contained in Appendix B are hereby incorporated in the license.

CPCo shall operate the facility in accordance with the Technical l

Specifications and the Environmental Protection Plan.

Amendment No. 171

3 (3) CPCo shall implement and maintain in effect all provisions of the l approved fire protection program as described in the Final Safety Analysis Report for the facility and as approved in the SERs dated 09/01/78, 03/19/80, 02/10/81, 05/26/83, 07/12/85, 01/29/86, 12/03/87, and 05/19/89 and subject to the following provisions:

CPCo may make changes to the approved fire protection program without prior approval of the Commission only if those changes l a.

would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire.

b.

CPCo may alter specific features of the approved fire l

protection program provided:

I 1

Such changes do not result in failure to complete the fire protection program as approved by the Commission.

CPCo l

shall maintain in auditable form, a current record of all such changes, including an analysis of the effects of the change on the fire protection program and shall make such records available to the Commission Inspectors upon l

request. All changes to the approved program shall be reported annually, along with the FSAR revision; and Temporary changes to specific fire protection features i-which may be necessary to accomplish maintenance or i

modifications are acceptable provided interim compensatory measures are implemented.

D.

The facility has been granted certain exemptions from the requirements i

of Section Ill.G of Appendix R to 10 CFR Part 50, " Fire Protection l

Program for Nuclear Power Facilities Operating Prior to January 1, 1979." This section relates to-fire protection features for ensuring the systems and associated circuits used to achieve and maintain safe shutdown are free of fire damage.

These exemptions were granted and sent to CPCo in letters dated February 8, 1983, July 12, 1985, and l

July 23, 1985.

In addition, the facility has been granted certain exemptions from Appendix J to 10 CFR Part 50, " Primary Reactor Containment Leakage Testing for Water Cooled Power Reactors." This section contains leakage test requirements, schedules and acceptance criteria for tests of the leak-tight integrity of the primary reactor containment and systems and components which penetrate the containment.

These exemptions were granted and sent to CPCo in a letter dated l

December 6, 1989.

These exemptions granted pursuant to 10 CFR 50.12, are authorized by law, will not present an undue risk to the public health and safety, and are consistent with the common defense and security. With these exemptions, the facility will operate, to the extent authorized i

herein, in conformity with the application, as amended, the provisions

)

of the Act, and the rules and regulations of the Commission.

Amendment No. H e,171

4 E.

CPCo shall fully implement and maintain in effect all provisions of the Commission-approved " Palisades Plant Physical Security Plan,"

" Palisades Plant Suitability Training and Qualification Plan," and

" Palisades Plant Safeguards Contingency Plan," and all approved amendments.

CPCo may make changes to these plans without prior Commission approval, if the changes do not decrease the safeguards effectiveness of the plans, in accordance with 10 CFR 50.54(p)(2).

F.

Except as otherwise provided in the Technical Specifications or Environmental Protection Plan, the licensee shall report any violations of the requirements contained in Section 2.C of this license in the following manner:

initial notification shall be made within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to the NRC Operations Center via the Emergency Notification System with written follow-up within 30 days in accordance with the procedures described in 50.73(b), (c), and (e).

G.

CPCo shall have and maintain financial protection of such type and in l such amounts as the Commission shall require in accordance with Section 170 of the Atomic Energy Act of 1954, as amended, to cover public liability claims.

H.

This license is effective as of the date of issuance and shall expire at midnight on March 14, 2007.

FOR THE NUCLEAR REGULATORY COMMISSION Original Signed By:

Thomas E. Murley Thomas E. Murley, Director Office of Nuclear Reactor Regulation Attachments:

1.

Appendix A - Technical Specifications 2.

Appendix B - Environmental Protection Plan Date of Issuance:

February 21, 1991 Amendment No MB,171

3.1 PRIMARY C00LANLSYIIEM 3.1.1 Operable Components (continued) 813.11 When primary coolant boren concentration is being changed, the process must be uniform throughout the primary coolant system volume to prevent stratification of primary coolant at lower boron concentration which could result in a reactivity insertion. Sufficient mixing of the primary coolant is assured if one shutdoun cooling or one primary coolant pump is in operation.'" The shutdoun cooling pump will circulate the primary system volume in less than 60 minutes when operated at rated capacity.

By imposing a minimum shutdown cooling pump flow rate of 2810 gpe, sufficient time is provided for the operator to terminate the boron dilution under asymmetric flow corditions.* The pressurizer volume is relatively inactive, therefore it will tend to have a boron concentration higher than the rest of the j

primary coolant system during a dilution operation. Administrative procedures will provide for use of pressurizer sprays to maintain a nominal spread between the boron concentration in the pressurizer and the primary system during the addition of boron.iai The 57% pressurizer level, in section 3.1.lh(4), is not an analytical result, but simply a decision point between having and not having a bubble.

It was chosen to agree with the maximum programmed level during power operation.

The limitation, in section 3.1.11, on operating. P-50A and P-50B together with T, below 300*F allows the Pressure Temperature limits of Figures 3-1 and 3-2 to be higher than they would be without this limit.

The FSAR safety analysis was performed assuming four primary coolant pumps were operating for accidents that occur during reactor operation. Therefore, reactor startup above hot shutdown is not permitted unless all four primary coolant pumps are operating. Operation with three primary coolant pumps is permitted for a limited time to allow the restart of a stopped pump or for reactor internals vibration monitoring and testing.

)

Requiring the plant to be in hot shutdown with the reactor tripped from the C-06 panel, opening the 42-01 and 42-02 circuit breakers, assures an inadvertent rod bank withdrawal will not be initiated by the control room operator.

Both steam generators are required to be operable whenever the temperature of the primary coolant is greater than the design temperature of the shutdown cooling system to assure a redundant heat removal system for the reactor.

The transient analyses were performed assuming a vessel flow at hot zero power (532*F) of 140.7 x lif lb/hr minus 6% to account for flow measurement j

uncertainty and core flow bypass. A DNB analysis was performed in a i

parametric fashion to determine the core inlet temperature as a function of l

pressure and flow for which the minimum DNBR is equal to the DNB correlation safety limit. This analysis includes the following uncertainties and allowances: 2% of rated power for power measurement; 10.06 for ASI measurement; 122 psi for pressurizer pressure;*17*F for inlet temperature; l

and 3% measurement and 3% bypass for core flow In addition, transient biasas were included in the determination of the allowable reactor inlet temperature.

3-2 Amendment No. 67, 86, W, W, W, W, MB, M9,171

1 3.1 PRIMARY COOLANT SYSTEM BA111 (continued)

The limits of validity of the Tc equation are:

i 1800 s pressure s 2200 psia 100.0 x 10' s Vessel Flow s 150 x 10' lb/h l

ASI as shown in the COLR.

With measured primary coolant system flow rates > 150 M lbm/hr, limiting the l

maximum allowed inlet temperature to the Tc".LCO at 150 M lbm/hr increases the margin to DNB for higher PCS flow rates The Axial Shape Index alarm channel is being used to monitor the ASI to i

ensure that the assumed axial power profiles used in the development of the inlet temperature LCO bound measured axial power profiles. The signal representing core power (Q) is the auctioneered higher of the neutron flux power and the Delta-T power. The measured ASI calculated from the excore detector signals and adjusted for shape annealing (Y) and the core power i

constitute an ordered pair (Q,Y,).

An alarm signal is activated before the ordered pair exceed the boundaries specified in the COLR.

The requirement that the steam generator temperature be s the PCS temperature when forced circulation is initiated in the PCS ensures that an energy addition caused by heat transferred from the secondary system to the PCS will not occur. This requirement applies only to the initiation of forced circulation (the start of the first primary coolant pump) when the PCS cold leg temperature is < 430*F. However, analysis (Reference 6) shows that under limited conditions when the Shutdown Cooling System is isolated from the PCS, forced circulation may be initiated when the steam generator temperature is higher than the PCS cold leg temperature.

References (1) Updated FSAR, Section 14.3.2.

(2) Updated FSAR, Section 4.3.7.

(3) Deleted (4)

EMF-92-178, Revision 3, Section 15.0.7.1 (5) ANF-90-078 (6) Consumers Power Company Engineering Analysis EA-A-NL-89-14-1 3-3 Amendment No. M, R, 4M, 448, 4M, M4, M7, 443, 4M, M9, M9,171

........a.-

3.1 PRIMARY COOLANT SYSTEM Snecification 3.1.2 PCS pressure, PCS temperature, and PCS heatup and cooldown rates shall be maintained within the following limits:

a.

The primary coolant system (PCS) pressure shall be maintained within the limits of Figures 3-1 and 3-2.

b.

The pressurizer heatup rate shall be maintained s 100*F/ hour **; the pressurizer cooldown rate shall be maintained s 200'F/ hour.

c.

The primary coolant system (PCS) heatup and cooldown rates shall be l

maintained within the following limits:

Reactor Vessel Average Hourly Average Hourly l

Inlet Tennerature (T)

Heatun Rate Limit Cooldown Rate Limit T s 170*F 20*F/ hour 40*F/ hour 250 2 T > 170*F 40*F/ hour 40*F/ hour 350 > T > 250*F 60*F/ hour **

60*F/ hour T 2 350*F 100*F/ hour 100*F/ hour When shutdown cooling isolation valves M0-3015 and M0-3016 are open, PCS heatup rate shall be maintained s 40*F/ hour and the pressurizer heatup rate shall be maintained s 60*F/ hour.

Anolicability Specification 3.1.2 applies at all times.

Action a.-

If the limits of Specification 3.1.2 are exceeded:

1.

Return to within limits within 30 minutes, and 2.

Determine that the PCS condition is acceptable for continued operation within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

b.

If any action required by 3.1.2a is not met and the associated completion time has expired:

1.

The reactor shall be placed in HOT SHUTDOWN within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and 2.

The reactor shall be placed in a COLD SHUTDOWN with PCS pressure less than 270 psia, within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.

3-4 Amendment No. N, 44, 66, 89, W, W, 4M, MB,171

l

.3.1 PRIMARY COOLANT SYSTEM Basis - Pressure Tennerature Limits:

e The Primary Coolant System Pressure-Temperature limits am calculated for a reactor vessel wall fluence of 2.192 x 10"nyt.

Before the radiation exposure of the reactor vessel exceeds that fluence, Figures 3-1 and 3-2 shall be updated in accordance with the following criteria and procedure:

1.

US Nuclear Regulatory Commission Regulatory Guide 1.99 Revision 2 has been used to predict the increase in transition temperature based on integrated fast neutron flux and surveillance test data.

If measurements on the irradiated specimens show increase above this curve, a new curve shall be constructed such that it is above and to the left i

of all applicable data points.

2.

Before the end of the integrated power period for which Figures 3-1 and 3-2 apply, the limit lines on the figures shall be updated for a new integrated power period. The total integrated reactor thermal power from i

start-up to the end of the new power period shall be converted to an equivalent integrated fast neutron exposure (E ;t 1 MeV). Such a conversion shall be made consistent with the dosimetry evaluation'of capsule W-290(12).

3.

The limit lines in Figures 3-1 and 3-2 are basad on the requirements t,i Reference 9, Paragraphs IV.A.2 and IV.A.3.

All components in the primary coolant system are designed to withstand the effects of cyclic loads due to primary system temperature and pressure changes.(1) These cyclic loads are introduced by normal unit load transients, reactor trips and start-up and shutdown operation. During unit start-up and shutdown, the rates of temperature and pressure changes are limited. A maximum plant heatup and cooldown limit of 100*F per hour for the reactor vessel and a maximum heatup limit of 100*F per hour and cooldown limit of 200'F per hour for the pressurizer are consistent with the design number of cycles and satisfies stress limits for cyclic operation.(2) i The reactor vessel plate and material opposite the core has been purchased to a specified Charpy V-Notch test result of 30 ft-lb or greater at an NDTT of +

10*F or less. The vessel circumferential weld has the highest RTNDT of plate, weld and HAZ materials at the fluence to which the Figures 3-1 and 3-2 apply.(10) The unirradiated RTNDT has been determined to be -56*F.(11) An RTNDT of -56*F is used as an unirradiated value to which irradiation effects are added.

In addition, the plate has t*en 100% volumetrically inspected by ultrasonic test using both longitudinal and shear wave methods. The remaining material in the reactor vessel, and other primary coolant system components, meets the appropriate design code requirements and specific component function and has a maximum NDTT of +40*F.(5)

As a result of fast neutron irradiation in the~ beltline region of the core, there will be an increase in the RTun with operation. The integrated fast neutron (E >l Mev) fluxes of the reactor vessel are contained in Reference 13.

3-7 Amendment No. N, 41, H, 89, W, 4W, H+, MB,171

3.3 EMERGENCY CORE COOLING SYSTEM (Ccntinu;d) 3.3.3 Prior to returning to the Power Operation Condition after every time the plant has been placed in the Refueling Shutdown Condition, or the Cold Shutdown Condition for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and testing of Specification 4.3.h has not been accomplished in the previous 9 months, or prior to returning the check valves in Table 4.3.1 to service after maintenance, repair or replacesent, the following conditions shall be met:

a.

All pressure isolation valves listed in Table 4.3.1 shall be functional as a pressure isolation device, except as specified in b. Valve leakage shall not exceed the amounts indicated.

b.

In the event that integrity of any pressure isolation valve specified in Table 4.3.1 cannot be demonstrated, at least two valves in each high pressure line having a non-functional valve must be in and remain in, the mode corresponding to the isolated condition."'

c.

If Specification a. and b. cannot be met, an orderly shutdown shall be initiated and the reactor shall be in hot shutdown condition within 12 i

hours, and cuid shutdown within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

i

' Motor-operated valves shall be placed in the closed position and power supplies deenergized.

3.3.4 Two HPSI pumps shall be operable when the PCS temperature is >325'F.

a)

One HPSI pump may be inoperable provided the requirements of Section 3.3.2.c are met.

3.3.5 Two HPSI pumps shall be rendered inr.apable of injection into the PCS when PCS temperature is <300*F, if the reactor vessel head is installed.

Note:

Specification 3.3.5 does not prohibit use of the HPSI pumps for emergency addition of makeup to the PCS.

3-30 Amendment No. M, W, W, W, W, M3 171

3.3 EMERRENCY CORE COOLING SYSTEM (Continuid)

BAlli The normal procedure for starting the reactor is, first, to heat the primary coolant to near operating temperature by running the primary coolant pumps.

The reactor is then made critical by withdrawing control rods and diluting boron in the primary coolant."' With this mode of start-up, the energy stored in the primary coolant during the approach to criticality is substantially equal to that during power operation and, therefore, all engineered safety features and auxiliary cooling systems'are required to be fu?ly operable. During low-temperature physics tests, there is a negligible amount of stored energy in the primary coolant; therefore, an accident comparable in severity to the design basis accident is not possible and the engineered safeguards' systems are not required.

i The SIRW tank contains a minimum of 250,000 gallons of water containing a minimum of 1720 ppm boron.and a maximum of 2500 ppe. This is sufficient boron concentration to provide a 5% shutdown margin with all control rods withdrawn and a new core at a temperature of 60*F.

Heating steam is provided to maintain the tank above 40*F to prevent freezing. The 1.43% boron (2500 ppm) solution will not precipitate out above 32*F.

The source of steam during normal plant operation is extraction steam line in the turbine cycle.

The limits for the safety injection tank pressure and volume assure the required amount of water injection during an accident and are based on values used for the accider.c analyses. The minimum 174-inch level corresponds to a volume of 1040 ft* and the maximum 200-inch level corresponds to a volume of 1176 ft*.

Prior to the time the reactor is brought critical, the valving of the safety injection system must be checked for correct alignment and ~ appropriate valves locked.

Since the system is used for shutdown cooling, the valving will be changed and must be properly aligned prior to start-up of the reactor.

The operable status of the various systems and components is to be demonstrated by periodic tests. A large fraction of these tests will be performed while the reactor is' operating in the power range.

If a component is found to be inoperable, it will be possible in most cases to effect repairs and restore the system to full operability within a relatively short time.

For'a single component to be inoperable does not negate the ability of the system to perform its function, but it reduces the redundancy provided in the reactor design and thereby limits the 3-31 Ch r;: M. 1 Amendment No. 444, +36, 443,171

3.7 ELECTRICAL SYSTEMS (Cent'd) a.

Station power transformer 1-2 (2400 V) may be inoperable for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> provided the operability of both diesel generators is demonstrated immediately.

b.

Start-up transformer 1-2 (2400 V) may be inoperable for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> provided the operability of both diesel generators is demonstrated immediately. Continued operation beyond 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is permissible provided that a report is sent to the NRC immediately with an outline of the plans for prompt restoration of the start-up transformer and the additional precautions to be taken while the transformer is out of service, and continue operating until notified differently by the NRC.

2400 V engineered safeguards bus IC or ID may be inoperable for up to 8 c.

hours provided'the operability of the diesel generator associated with the operable bus is demonstrated immediately and there are no inoperable engineered safety feature components associated with the operable bus.

d.

480 V distribution bus 11 or 12 may be inoperable for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> provided there are no inoperable safety feature components associated 1

with the operable bus.

MCC No. I and 7 or 2 and 8 may be inoperable for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> provided e.

there are no inoperable safety feature components associated with the l

operable pair of MCC.

f.

125 V d-c bus No. I or 2 may be inoperable for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> provided there are no inoperable safety feature components associated with the operable bus and adequate portable emergency lighting is available during the inoperability of the No. 2 bus, g.

One of the four preferred a-c buses may be inoperable for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> provided the reactor protection and engineered safety feature systems supplied by the remaining three buses are all operable.

h.

One of the station batteries may be inoperable for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, providing both battery chargers on the affected bus are in operation.

l 1.

One of the diesel generators may be inoperable for up to 7 days (total for both) during any month, provided the other diesel is started to verify operability, shutdown and the controls are left in the automatic mode, and there are no inoperable engineered safety feature components associated with the operable diesel generator.

I 3-42 Amendment No. 88,171

3.11 POWER DISTRIBUTION INSTRUMENTATION 3.11.1 INCORE DETECT 0RE LIMITING CONDITION FOR OPERATION The incore detection system shall be operable:

a.

With at least 160 of the 215 possible incore detectors and 2 incores per axial level per core quadrant.

b.

With the incore alarming function of the datalogger operable and alare set points entered into the datalogger.

APPLICABILITY (1)

Item a. above is applicable when the incore detection system is used for:

Measuring quadrant power tilt, Measuring radial peaking factors, Measuring linear heat rate (LHR), or Determining target Axial Offset (AO) and excore monitoring allowable power level.

(2)

Items a. and b. above are applicable when the incore detection system is used for monitoring LHR with automatic alarms. (Incore Alarm System.)

ACTION 1:

With less than the required number of incore detectors, do not use the system for the measuring and calibration functions under (1) above.

ACTION 2:

With the alarming function of the datalogger inoperable, do not use the system for automatic monitoring of LHR (Inoperable incere Alarm System).

Operation may continue using the excore monitoring system as specified in 3.11.2 or by meeting the requirements of 3.23.1.

Basis The operability of the incore detectors with the specified minimum complement of eqtipment ensures that the measurements obtained from use of this system accurately represent the spatial neutron flux distribution of' the reactor core. The operability of the incore alarm system depends on the availability of the datalogger as well-as the operability of a minimum number of incore detectors.

Incore alarm set points must be updated periodically based on measured power distributions. The incore detector Channel Check is nonna11y performed by an on-line computer program that correlates readings with one l

another and with computed power shapes in order to identify inoperable detectors.

Amendment No. 60, 68, 68, 444, MB,171 3-56

o 3.15 Delcted 1

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F I

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Anendment No. 81, Ma,171 3-62

,i 3.16 ESF SYSTEM INSTRUMENTATION SETTINGS Basis Table 3.16 (continued) i 4.

Steam Generator Low Pressure - A separate Steam Generator Low i

Pressure (SGLP) signal is provided from each generator. The individual channel signals from each generator are combined in 2 out of 4 logic to initiate a SGLP signal for that generator.

Each SGLP signal actuates closure of both Main Steam Isolation Valves (MSIVs) and closure of the feed water regulating valve and its bypass for the associated generator.

The setpoint was chosen to be low enough to avoid actuation during plant operation, but be close enough to full power operating pressure to be 4

actuated quickly in the event of a MSLB. The setting includes a -22 l

psi uncertainty allowance and was the setting used in the FSAR Section 14 analysis '"

5.

Steam Generator Low Level - The Auxiliary Feedwater Actuation Signal (AFAS) is initiated by 2 out of 4 low level signals occurring for either steam generator. The setpoint is the same as that for Rentor Trip.

The setpoint was chosen to assure that Auxiliary Feedwater Flow would be initiated while the steam generator could still act as a heat sink and steam source, and to assure that a reactor trip would not occur on low level without the actuation o'f Auxiliary Feedwater.

6.

SIRW Tank Low Level -'Four SIRWT level sensors are arranged to provide two independent Recirculation Actuation Signals.

Each low level sensor is powered from a separate Preferred AC bus; thus two are l

ultimately powered from each station battery.

Each Recirculation Actuation Signal (RAS) circuit is wired with the contacts from the pair of level sensors powered from the same battery in parallel. These two i

parallel circuits are wired in series, producing a "I out of 2 taken twice" logic.

RAS for each train is actuated by either switch from the left battery sensing low level concurrently with either switch from the

{

right battery. This circuit is illustrated in reference 3.

The RAS signal is actuated by separate sensors from those which provide tank level indication. The allowable range of 21" to 27" above the tank floor corresponds to 1.1% to 3.3% indicated level. T setting is near the midpoint of the allowable range. ypically the actual Each RAS actuates the valves in the injection and spray pump suction l

lines for the associated train switching the water supply from the SIRW tank to the containment sump for a recirculation mode of operation. The time required to reach the RAS setpoint depends.on the initiating event.

Following a DBA, RAS would occur after a period of approximately 20 minutes assuming all engineered safeguards pumps are operating at runout flows. The setpoint was chosen to provide adequate water in the containment sump for HPSI pump net positive suction head following an accident, but prevent the pumps from running dry during the 60 second switchover.

B 3.16-2 Amendment No. M3,171

-wr

t 3017 INSTRUNENTATION SYSTENS Basis:

Instrumerttation Systems 3.17 (continued)

Table B 3.17-1 Instruments Affectina Nultiple Specifications Affected Required Instrument channels Specifications Source Range NI-01/03 & 02/04 Count Rate Signal 3.8.e Source Range NI-01/03 & 02/04 Count Rate Signal 3.17.6 #1 Source Range NI-01/03 Count Rate Indication 9 C-150 3.17.5 #1 Wide Range NI-01/03 & 02/04 Flux level 10-4 interlock 3.17.1 #3, 4, 6, 10, & 11 Wide Range NI-01/03 & 02/04 Start-up Rate 3.17.1 #3 1

Wide Range NI-01/03 & 02/04 Flux Level Indication 3.17.4 #3 Wide Range NI-01/03 & 02/04 Flux Level Indication 3.17.6 #1 Power Range NI 08, Power level signal 3.17.6 #12, 15, 18 l

Power Range NI 08, Power level signal 3.23.1 #A.2 Power Range NI 08, Q-power 3.17.1 #2 & 4 Power Range NI 08, ASI 3.17.1 #2 & 4 Power Range NI 08, ASI 3.17.6 #16 l

Power Range NI 08, ASI 3.1.1 #g Power Range NI-05 & 06; 15% interlock 3.17.1 #3 & 7 Power Range NI-05 & 06; 15% interlock 3.17.6 #18 PCS TC, Temperature signal 3.17.1 #4 PCS TC, Temperature indication 3.17.5 #6 &7 PCS TC, Q-power 3.17.1 #2 & 4 PCS TC, Q-power 3.17.6 # 14 PCS TH, Temperature indication 3.17.5 #5 & 6 PCS TH, Q-power 3.17.1 #2 & 4 PCS TH, Q-power 3.17.6 # 14 Pressurizer Pressure PI-0102 A-D, Pressure signal 3.17.1 #4 & 5 Pressurizer Pressure PI-0102 A-D, Pressure signal 3.17.2 #1.d Pressurizer Pressure PI-0110, Pressure indication 3.17.5 #2 Steam Generator Level LI-0751 & 0752 A-D, Level Signal 3.17.1 #8 & 9 Steam Generator Level LI-0751 & 0752 A-D, Level Signal 3.17.2 #3.c & d Steae Generator Level LI-0751A & 0752A, Level indication 3.17.5 # 10 & 11 Steam Generator Pressure PI-0751 & 0752 A-D, Pressure Signal 3.17.1 #10 & 11 Steam Generator Pressure PI-0751 & 0752 A-D, Pressure Signal 3.17.3 #3.c & d Steam Generator Pressure PI-0751 & 0752 A-D, Pressure Indication 3.17.4 #13 & 14 Steam Generator Pressure PI-0757 & 0758 A&B, WR Pressure Indication 3.17.5 #8 & 9 Containment Pressure PS-1801, 2, 3, & 4, switch output 3.17.1 # 12 Containment Pressure PS-1801, 2, 3, & 4, switch output 3.17.3 #1.a & b B 3.17-3 Amendment No. M2,171

3.17 INSTRUMENTATION SYSTEMS Basis: 3.17.6 Other Safety Features The Safety Functions required by Specification 3.17.6 provide alarm and indication functions to assist the operator in monitoring plant conditions.

None of the required functions provide automatic actions assumed to be available in the safety analysis, therefore, operation may continue even though the function is degraded or lost provided that the specified action is met.

The provisions of Specifications 3.0.4 and 4.0.4 are not applicable to several required instrument functions, as noted in Table 3.17.6.

These instrument functions have sufficient redundancy to provide their required functions with one or more installed channels operable. The exception to 3.0.4 and 4.0.4 allows changing of plant operating conditions, but the required actions require eventual return to service.

Basis: Applicability 3.17.6 Specification 3.17.6 involves miscellaneous instruments with widely differing function. The applicability for each required instrument is provided in the Applicable Conditions column of Table 3.17.6.

Basis: Action statements 3.17.6 The listed Action is required to be completed within the specified time if the conditions of the specification are not met.

If, prior to expiration of the specified completion time, the required conditions are restored, completion of the Action is not required. Each specified completion time starts at the time it is discovered that the Action statement is applicable.

Since Table 3.17.6 consists of instruments of widely different function, each table entry has its own Action statements whose numbering corresponds to that of the table entries. These Actions are discussed following the basis for the associated channel.

Basis: Table 3.17.6 1.

Neutron Flux Monitorina - Two channels of neutron flux monitoring (NI-01/03 and NI-02/04) are required to be OPERABLE when there is fuel in the reactor and the flux is s 10% RATED POWER. When flux is greater than 10",

the requirements of Specification 3.17.1 assure adequate flux monitoring capability. Neutron flux channels are used to monitor core reactivity changes.

If only one section of a neutron flux monitoring channel, source or wide range, is functioning, the neutron flux monitoring channel may be considered OPERABLE if it is capable of detecting the existing reactor neutron flux, for example, with the source range count rate indicator functioning properly, indicating 150 cpm, in reasonable agreement with the other source range, a neutron flux monitor channel may be considered OPERABLE even though its wide range indicator is not functioning.

B 3.17-25 Amendment No. M3,171

,v l

3.17 INSTRUMENTATION SYSTEMS i

Basis: Table 3.17.6 (continued)

The count rate section of the wide range neutron flux monitoring channels is i

capable cf detecting flux levels below the indicating scale.

Flux levels decraase with time whi?e the reactor is shutoown. After extended shutdowns the flux level may decrease below the indicating range. When flux is below the indication range, chunel OPERABILITY may be verified by using scaler-counters or other additiontl instrumentation.

Action 3.17.6.1 - One or two Neutron Flux Monitorina channels inonerable -

When there are fewer than two OPERA 8LE Neutron Flux Monitoring channels, complete monitoring of core reactivity is not possible. All positive reactivity changes must be terminated immediately, the reactor must be shutdown, if it was critical, and SHUTDOWN MARGIN verified within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and each 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter until the required monitoring is restored.

The completion time of "immediately" does not mean " instantaneously", rather it implies " start as quickly as plant conditions permit and continue until completed."

2.

Rod Position Indication - Two channels of rod position indication are required to be OPERABLE for each full-length and each part-length rod.

Rod position indication is required to allow verification that the rods are positioned and aligned as required. Rod position channels are required to be OPERABLE whenever more than one CRDM is capable of rod withdrawal.

It is not required when only a single rod may be withdrawn for two reasons: first, it is necessary to withdraw a rod in order to perform the calibration necessary to declare the position indication channels OPERABLE, and second, the safety analyses assume that the most reactive rod is stuck in the fully withdrawn position. Both rod position channels are calibrated to read the height of the bottom of the control rod blade, in inches, above the fully inserted position.

l Primary rod position indication is provided by a gear train driven from the CRDM drive package, below the clutch. The gear train actuates cam operated limit switches and a synchro. The limit switches also actuate some of the rod position indication lights. The synchro, together with the PIP section of the plant computer, operate the digital position indication.

Both the limit switches and the synchro signal are also used for alarm and control functions. The " upper electric limit" and " lower electric limit" limit switches stop the CRDM motor when the rod nears full mechanical travel of the CRDM. This provides redundant assurance that the CRDM buffer piston is not driven into the lower hard stop and that the pinion gear is not driven beyond the end of the teeth on the rack.

The primary rod position system is considered OPERABLE, for purposes of this specification, if the digital position readout or the cam operated position indication lights give positive indication of rod position.

Secondary Position Indication (SPI) is operated by a magnet integral with the connector nut and a magnetically operated reed switch stack attached to the CRDM housing. The reed switches are located at uniform intervals along the travel of the c>nnector nut.

B 3.17-26 Amendment No. Ma,171

a 3.17 INSTRUMENATION SYSTEMS Basis: Table 3.17.6 (continued) 4 The reed switches are wired so that the voltage read across the reed switch stack is proportional to rod position. There is a dead band, near the bottom of the travel, where the CRDM housing seismic support prevents operation of the switches. SPI also provides alarms, position indication lights, and control functions based on rod position.

.The SPI for each control rod is considered OPERABLE, for purposes of LCO, if there are no occurrences, other than the seismic support dead band, where two adjacent switches fail to respond to rod motion.

Action 3.17.6.2 - One rod position indication channel inoperable - If one channel of rod position indication is inoperable, control and alarm functions may also be inoperable. The position of each rod in the associated group must be verified to be within the limits of specification 3.10 within 15 minutes after moving any rod.

3.

Safety Iniection Refuelina Water Tank Temperature - SIRWT temperature instrumentation is required to verify that the SIRWT temperature is within limits. Two channels of temperature indication are provided.

SIRWT temperature instrumentation is not required below 300*F Taire because the SIRWT and systems supported by the SIRWT are not required to be OPERABLE below 300*F Tave.

SIRWT temperature indication has been excepted from the provisions of Specifications 3.0.4 and 4.0.4 because alternate means of obtaining the required information are readily available.

Action 3.17.6.3 - One or two SIRWT temoerature channels inonerable - With installed SIRWT temperature indication inoperable, operation may continue as long as temperature can be verified to be above the limit. The tank is not insulated and is accessible so alternate means of determining temperature are relatively simple. When ambient temperatures are well above the SIRWT limit, outside air temperature may be assumed to represent SIRWT temperature.

4.

Main Feedwater Flow Indication - The Main Feedwater Flow measurements are necessary to perform the required daily calorimetric calculation. One feedwater flow instrument is provided for each feed line.

These flow indicators are the same instruments which provide flow indication to the Feedwater Control System.

The instrumentation is not required below 15% RATED POWER where calorimetric calculations are not required.

Action 3.17.6.4 - Main Feedwater Flow indication inocerable - If feedwater flow indication is inoperable, this specification allows operation to continue if alternate indication can be provided to allow completion of the required daily calorimetric calculation. The inoperable channel must be restored to OPERABLE status prior to the next reactor startup, as required by Specification 3.0.4.

B 3.17-27 Amendment No. MB,171

3.17 INSTRUMENTATION SYSTEMS Basis: Table 3.17.6 (continued) 5.

Main Feedwater Temoerature Indication - The Main Feedwater Temperature measurements are necessary to perform the required daily calorimetric calculation. One feedwater temperature instrument is provided for each feed line. The instrumentation is not required below 15% RATED POWER where calorimetric calculations are not required.

Action 3.17.6.5 - Main Feedwater Temperature indication inoperable - If feedwater temperature indication is inoperable, this specification allows operation to continue if alternate indication can be provided to allow completion of the required daily calorimetric calculation. The inoperable channel must be restored to OPERABLE status prior to the next reactor i

startup, as required by Specification 3.0.4.

6.

Auxiliary Feedwater Flow - The AFW system is arranged as two independent trains of pumps, piping, flow control valves and electrical controls.

Each train is capable of feeding each steam generator through separate feed lines and flow control valves.

Each AFW feed line is provided with two separate flow indication channels.

One channel provides an input to the associated AFW flow control valve as well as control room flow indication; the other provides flow indication in the control room. A flow switch from each of the flow indicator channels provides a flow signal to the AFW pump sequencing circuitry.

In addition, two of the flow transmitters associated with the turbine driven AFW pump, those which do not pro' vide flow control, can be manually switched into a completely separate circuit which provides AFW flow information at Alternate Shutdown Panel C-150.

The AFW flow channels are not required to be OPERABLE when the PCS is below 300*F because the AFW system in not required to be OPERABLE below 300*F.

Action 3.17.6.6.1 - One AFW flow indicator inoperable - If one flow channel becomes inoperable, the OPERABILITY of the associated flow control valve must be determined. Those flow indication channel failures which could prevent flow through that feed line cause the valve to be inoperable.

Flow indication channel failures which affect only indication, or which cause the valve to fail open do not necessarily cause the valve to be inoperable.

Action 3.17.6.6.2 - Two AFW flow indicators inoperable - If two flow indication channels for one AFW feed line become inoperable there is no way to verify flow through that line; the associated AFW flow control valve must be declared inoperable.

The completion time of "immediately" does not mean

" instantaneously", rather it implies " start as quickly as plant conditions permit and continue until completed."

7.

PCS Leakaae Detection Instrumentation - Four diverse systens for PCS leak detection are required to be OPERABLE, any one Containment Hum dity Monitor, any one Containment Atmosphere Gaseous Activity Monitor, any one Containment Air Cooler Condensate Level Switch, and any one Containment Sump Level indicator.

The air cooler level switch must be associated with an operating air cooler.

B 3.17-28 Amendment No. M B,171

3.17 INSTRUMENTATION SYSTEMS Basis: Table 3.17.6 (continued)

Footnotes (b) and (c) are intended to clarify that the requirement is for one instrument channel of each type to be operable, and that continued operation is not permitted unless at least one instrument channel, out of all those specified, is operable.

If one OPERABLE Instrument of each type is not available, the appropriate Action statement must be followed; if no PCS leakage Detection instrument channels are operable, Action 3.17.6.21 is

. applicable.

The PCS leakage detection instrumentation systems are not required to be OPERABLE when the PCS temperature is below 300*F because the consequence of leakage at reduced temperature and pressure is small, and because the PCS is accessible for local inspection.

Action 3.17.6.7.1 - One reauired leak detection system inonerable - Operation may continue with one of the required four types of leak detection systems inoperable, but one instrument of each type must be restored to OPERABLE status prior to the next startup from COLD SHUTDOWN.

Several of the instruments cannot be conveniently repaired with the plant at elevated temperature due to their location or their impact on containment integrity.

Three separate leak detection systems, together with daily PCS inventory checks, are considered adequate for continued operation.

Action 3.17.6.7.2 - Two or three reauired leak detection systems inoperable -

Daily PCS inventory calculations provide adequate leakage detection for limited periods. Thirty days is considered adequate time in which to accomplish repairs necessary to return at least three of the required instruments to operable status.

8.

Primary Safety Valve Position Indication - Each Primary Safety valve is provided with two means of detecting an open or leaking valve; one acoustical monitor and one tail pipe temperature indicator.

Primary Safety Valve position' indication instrumentation is not required to be OPERABLE when the PCS temperature is below 300*F because the consequence of leakage at reduced temperature and pressure is small, and because the PCS is accessible for local inspection.

Primary Safety Valve position indication has been excepted from the requirements of Specifications 3.0.4 and 4.0.4 to permit a startup from HOT SHUTDOWN with an inoperable channel. Without such an exception, no startup could be made without cooling down to repair the inoperable channel.

Action 3.17.6.8 - One Primary Safety Valve oosition indication channel inonerable - The Primary Safety valves are located on top of the pressurizer.

During operation at elevated temperatures, the position. indication is not accessible for repair. One OPERABLE channel provides sufficient capability to detect leakage for limited periods of time. The inoperable channel must be restored to OPERABLE status prior to the next start up from COLD SHUTDOWN.

B 3.17-29 Amendment No. MB,171

3.17 INSTRUMENTATION SYSTEMS Basis: Table 3.17.6 (continued)

I 9.

Power Doerated Relief Valve Position Indication - Each PORV is provided with three means of position detection; a stem position indicator, an acoustical monitor mounted on the valve, and a temperature indicator punted on the common tailpipe. The acoustic monitors and temperature indicator provide indication of leakage through the PORV and its associated block valve.

.PORV position indication is required to be OPERABLE except when the PCS is in COLD SHUTDOWN or when the PORV is isolated by a closed PORV block valve which has OPERA 8LE position indication. When the plant is in COLD SHUTDOWN, PORV leakage is of little consequence. When the PORV is isolated, the block valve position indication'provides the needed information.

PORV position indication has been excepted from the requirements of Specifications 3.0.4 and 4.0.4 to permit a startup from HOT SHUTDOWN with an inoperable channel. Without such an exception, ne startup could be made without cooling down to repair the inoperable channel.

Action 3.17.6.9 - One or two PORV nosition indication channels inoperable -

The PORVs are located on top of the pressurizer. During operation at elevated temperatures, the position indication is not accessible for repair.

One OPERABLE channel provides sufficient capability to detect le'akage for limited periods of time. The inoperable channels must be restored to OPERABLE status prior to the next start up from COLD SHUTDOWN.

10.

PORV Block Valve Position Indication ~- Each PORV block valve is provided with position indication lights operated.by limit switches on the valve motor operator and by a temperature indicator mounted on the common PORV tailpipe.

PORV block valve position indication is required to be OPERABLE except when the PCS is depressurized and vented through a monitored path.

The PORV block valves are required to be open at low temperatures so that the PORVs can provide Low Temperature Over Pressure protection.

PORV block Valve position indication has been excepted from the requirements of Specifications 3.0.4 and 4.0.4 to permit a startup from HOT SHUTDOWN with an inoperable channel. Without such an exception, no startup could be made without cooling down to repair the inoperable channel.

Action 3.17.6.10 - PORV Block Valve position indication inocerable - The PORV block valves are located on top of the pressurizer.

During operation at~

elevated temperatures, the position indication is not accessible for repair.

The PORV block valves are motor operated valves and are not likely to inadvertently change position. They are in series with the PORVs. During operation at elevated temperatures, when LTOP is not required, operation may continue with only one channel of position indication. When LTOP protection is required, but valve position lights are inoperable, the PCS is accessible and operation may continue if position of the block valves is verified each 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Inoperable channels must be restored to OPERABLE status prior to the next start up from COLD SHUTDOWN.

J B 3.17-30 Amendment No. MB,171

o.

3.17 INSTRUMENTATION SYSTEMS Basis: Table 3.17.6 (continued) 11.

SWS Break Detector -- Flow indicators measuring Service Water System flow into and out of the containment are used to actuate an alarm if in flow significantly exceeds outflow. Such a mismatch could be indicative of a

)

cooler leak or a pipe break. The Break Detector is intended to allow identification of a leaking cooler by isolation of service water to each cooler insuccession until the alarm clears. The Break Detector is strictly a l j

maintenance aid and is intended to provide no safety function.

(Ref. 12)

The SWS Break Detector is required to be OPERABLE at HOT STAND 8Y and above, when the containment is inaccessible for direct observation of leakage, yet the SWS is required" Specifications 3.0.4 and 4.0.4 are not applicable to the SWS break detector because it does not provide an accident related safety function.

Action 3.17.6.11 - SWS Break Detector inoperable - If the break detector is inoperable, it must be restored to OPERABLE status prior to the next startup.

12.

Flux - AT Power Comoarator - The Flux -- AT Power comparator compares the two Q Power inputs (Excore Power Range flux and AT power) for that RPS channel, provides a meter indicating the difference between these inputs, and initiates an alarm if the difference exceeds a set value.

Existence of a significant difference between the monitored signals indicates that either a flux tilt is developing, or that a calibration of the Excore Power Range or AT power circuits is required.

The Flux - AT Power Comparator is not required to be OPERABLE when the reactor is below 2% power because the differential temperature measurement is not meaningful at very low power levels.

Action 3.17.6.12.1 - One Flux - AT Power Comparator channel inocerable - With one channel inoperable, the three remaining power comparator channels are sufficient to assure that no unobserved flux tilt is developing. The inoperable channel must be restored to OPERABLE status prior to the next reactor startup.

Action 3.17.6.12.2 - Two Flux - AT Power Comparator channels inocerable -

With two power comparator channels inoperable, power must be limited to 70%

of RATED POWER to assure that no unobserved flux tilt causes local power limits to be exceeded.

13.

Rod Group Seauence Control / Alarm - The Rod position indication provides two regulating rod group sequence related functions.

The PIP section of the plant computer, using the signals from primary rod position indication synchros on the selected target rods, provides' the actual control of group sequencing relays in addition to monitoring the target rods for the correct group position relative to the other groups.

If the group position is not correct relative to the position of the other regulating groups, an Out-of-Sequence alarm is annunciated on the main control panels.

B 3.17-31 Amendment No. MB,171

3.17 INSTRUMENTATION SYSTEMS Basis: Table 3.17.6 (continued)

The SPI system - composed of the SPI input module and the Host computer -

also uses the signals from the primary rod position indication synchros to monitor the target rods for the correct group position relative to the other groups.

If the group position is not correct relative to the position of the other regulating groups, an Out-of-Sequence alarm is annunciated on the computer system.

If a primary rod position indication synchro input card were to lose power, the corresponding reed switch position from the SPI

. input module would be used in the Out-of-Sequence monitoring on the SPI system. The Out-of-Sequence alare provides assurance that the operator is aware of abnormal regulating rod positioning.

When only one control rod is capable of being withdrawn, group sequencing and Out-of-Sequence alarm provide no useful function and are not required.

Action 3.17.6.13 - Groun Rod Group Seauence Control / Alarm channel inocerable

- When either sequence function is inoperable, one of the methods of assuring correct control rod alignment is not available. Adequate assurance of correct rod positioning is retained by manual verification of regulating rod position after each occurrence of rod motion.

14.

Concentrated Boric Acid Tank Low Level Alarm - A common " Conc Boric Acid Tank to Level" alarm notifies the operator that one boric acid tank is below the required total inventory. There is one level switch mounted on each tank, either of which actuates the common alarm in the control room. These two switches and the connon alarm comprise the required channels.

The Concentrated Boric Acid Tank low level alarm is not required to be OPERABLE when the reactor is at HOT SHUTDOWN or below, because the inventory of boric acid is not required.

Action 3.17.6.14 - One or Two Conc Boric Acid Tank low level alarm channels inonerable - When either a boric acid tank low level alarm switch or the common alarm is inoperable, the level in the tank or tanks without an operable level alarm should be verified to be within limits each shift.

15.

Excore Detector Deviation Alarm - An alarm is derived by the Excore Detector Deviation Alarm channel on excessive flux tilt. The Excore Detector Deviation Alarm compares the combined average power reading of all four Excore Power Range channels to the average from each channel, and alarms if the setpoint is exceeded. One channel being significantly different from the average could indicate a developing Quadrant Power Tilt (Tq).

The Excore Detector Deviation Alarm is required to be OPERABLE above 25%

RATED POWER, when the Tq specification is applicable.

Action 3.17.6.15 - Excore Deviation Alarm inoperable - When the Excore Deviation Alarm is inoperable, continuous monitoring of Tq is unavailable.

The function of Tq monitoring must be maintained by manually calculating Tq each 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

B 3.17-32 Amendment No. MB,171

1-3017 INSTRUMENTATION SYSTENS

]

Basis: Table 3.17.6 (continued) i i

i

16. AXIAL SHAPE INDEX Alarm - The ASI Alarm Channel monitors the ASI using 1

the Excore upper and lower detector signals as inputs and provides an alarm when ASI administrative limits are exceeded.

This alarm is only functional above a nominal 15% indicated power when the High Startup Rate trip is bypassed.

It uses the High Startup Rate Pre-Trip

)

Unit to provide the alarm function, and shares the same alarm window.

It is not required to be OPERABLE below 25% RATED POWER.

4 i

f Action 3.17.6.16 - One or two ASI alarm channels inonerable - The ASI alarm i

is one function of the Thermal Margin Monitor.

Four channels are provided, I

but two are sufficient for ASI monitoring.

If one or two channels are i

inoperable, they must be restored prior to the next startup from COLD j

SHUTDOWN.

i 17.

Shutdown Coolina (SDC) Suction Valve Interlocks - Interlocks are l

provided for each SDC suction valve. These interlocks are pressure switches t

which prevent opening of the associated valve when PCS pressure is above the l

design pressure of the SDC system. One pressure switch is provided for each valve.

i The interlocks are required to be OPERABLE when PCS pressure exceeds 200 psia to assure that the SDC System is not over pressurized by inadvertent opening s

l of the suction valves at high PCS pressure.

J Action 3.17.6.17 - One or two SDC suction interlocks inonerable - When an i

interlock is inoperable assurance that the valve will not be opened with high j

PCS pressure is reduced. The circuit breaker for the motor operator on the

~

associated SDC suction valve must be racked out, except during actual i

operation of' the valve. The extra action of having to rack in and close the breaker prior to valve operation provides protection against inadvertent valve operation.

j 18.

Power Dependant Insertion Limit (PDIL) Alarm - PDIL Alarms are provided j

by both the PIP and the SPI sections of the plant computer. The SPI system is composed of the SPI input module and the Host computer.

Each system

{

i monitors the position of each regulating group target rod from the primary rod position synchros and compares it to a setpoint which is a function of power level.

If a primary rod position indication synchro input card were to lose power, the corresponding secondary reed switch position from the SPI a

input module would be used in PDIL monitoring on the SPI System.

The group f

deviation alarms assure that the operator is aware of any group misalignment.

Maintaining the rods above the PDIL, when the reactor is critical, assures J

i that adequate SHUTDOWN MARGIN is available.

The PDIL alarm is not required at HOT SHUTDOWN and below, since no more than one control rod would be withdrawn and the SHUTDOWN Margin calculation j

accounts for that.

i i

]

B 3.17-33 Amendment No. MB,171 i

i 1

3.17 INSTRUMENTATION SYSTEMS Basis: Table 3.17.6 (continued)

Action 3.17.6.18 - One PDIL alarm inoperable - With one PDIL alarm inoperable assurance of proper SHUTDOWN MARGIN is reduced. Additional assurance of proper SHUTDOWN MARGIN is provided by verification of proper group position within 15 minutes following any regulating rod motion.

.19.

Fuel Pool Area Radiation Monitor - The spent fuel pool is provided with two radiation monitors. These instruments provide warning of a release in the case of a fuel handling accident and provide the fuel pool criticality monitoring required by 10 CFR 70.24.

Action 3.17.6.19 - One or two Fuel Pool Area Monitors inoperable - With one or two Fuel Pool Area Radiation Monitors inoperable, fuel movement in the

{

spent fuel pool area must be stopped. The monitor must be restored to OPERABLE status or equivalent monitoring capability provided within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

The Fuel Pool is designed to be adequately subcritical even at zero pp'm boron concentration. The specified 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is adequate to repair the installed instrumentation or to provide other monitoring equipment without incurring undue risk of a criticality.

20. Containment R 'uelina Radiation Monitors - Two radiation monitors are located in the refueiing area of the containment which actuate the Containment High Radiation Logic when switched to the refueling mode.

In this mode, a high level alarm on either monitor will actuate containment isolation through the associated CHR logic channel.

The arrangement of these controls is illustrated in reference 7.

Action 3.17.6.20 - One or two Containment Refuelina Monitors inoperable -

With one or two Containment Refueling Radiation Monitors inoperable, stop REFUELING OPERATIONS in the containment. This eliminates the possibility of damaging an irradiated fuel bundle.

Action 3.17.6.21 - Reautred action AND associated completion time not met -

If any action specified by Action statements 3.17.6.1 through 3.17.6.18 (items 19 and 20 are not associated with reactor operation) is not met AND its completion time has expirer, the plant must be placed in a condition where the inoperable equipment is not required.

Twelve hours are allowed to bring the plant to HOT SHUTDOWN, and 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to reach conditions where the affected equipment is not required, to avoid unusual plant transients.

Both the 12 and the 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> time periods start when it is discovered that Action 3.17.21.6 is applicable.

I B 3.17-34 Amendment No. MB,171

4.0 SURVEILLANCE REQUIREMENTS 4.0.1 Surveillance requirements shall be applicable during the reactor operating conditions associated with individual Limiting Conditions for Operation unless otherwise stated in an individual surveillance requirement.

4.0.2 Each Surveillance Requirement shall be performed within the specified surveillance interval with a maximum allowable extension not to exceed 25 percent of the specified surveillance interval.

4.0.3 Failure to perform a Surveillance Requirement within the allowed surveillance interval, defined by Specification 4.0.2, shall constitute noncompliance irith the operability requirements for a Limiting Condition for Operation. The time limits of the action requirements are applicable at the time it is identified that a Surveillance Requirement has not been performed. The action requirements may be delayed for up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to permit the completion of the surveillance when the allowable outage time limits of the action requirements are less than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Surveillance Requirements do not have to be performed on inoperable equipment.

4.0.4 Entry into a reactor operating condition or other specified condition shall not be made unless the Surveillance Requirements associated with a Limiting Condition of Operation has been performed within the stated surveillance interval or as otherwise specified. This provision shall not prevent passage through or to plant conditions as required to comply with action requirements.

4.0.5 Surveillance Requirements for inservice inspection and testing of ASME Code Class 1, 2, and 3 components shall be applicable as follows:

a.

Inservice inspection of ASME Code Class 1, 2, and 3 components and 1

inservice testing of ASME Code Class 1, 2, and 3 pumps and valves shall be performed in accordance with Section XI of the ASME Boiler i

and Pressure Vessel Code and applicable Addenda as required by 10 CFR 50, Section 50.55a(g), except where specific written relief has been granted by the Commission pursuant to 10 CFR 50, Section 50.55a(g)(6)(1).

Amendment No. BG, H, M G, M a,171 4-1

4.0 ' BASIS Specifications 4.0.1 through 4.0.5 establish the general requirements applicable to Surveillance Requirements. These requirements are based on the Surveillance requirements stated in the code of Federal Regulations,.10 CFR i

50.36(c)(3):

" Surveillance requirements are requirements relating to test, calibration, or inspection to ensure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions of operation will be met."

i Specification 4.0.1 establishes the requirement that surveillances must be performed during reactor operating conditions or other conditions for which the requirements of the Limiting Conditions for Operation apply, unless otherwise stated in an individual Surveillance Requirement.

The purpose of this specification is to ensure that surveillances are performed to verify the operational status of systems and components and that parameters are within specified limits to ensure safe operation of the facility when the plant is in a reactor operating condition or other specified condition for which the associated Limiting Conditions for Operation are applicable.

Surveillance Requirements do not have to be performed when the facility is in an operational condition for which the requirements of the associated Limiting Condition for Operation do not apply, unless otherwise specified.

The Surveillance Requirements associated with a Special Test Exception are only applicable when the Special Test Exception is used as an allowable exception the requirements of a specification.

Specification 4.0.2 establishes the limit for which the specified time j

interval for Surveillance Requirements may be extended.

It permits an allowable extension of the normal surveillance interval to facilitate surveillance scheduling and consideration of plant operating conditions that may not be suitable for conducting the surveillance; e.g., transient conditions or other ongoing surveillance or maintenance activities.

It also provides flexih*11ty to accommodate the length of a fuel cycle for surveillances that are performed at each refueling outage and are specified with an 18-month surveillance interval.

It is not intended that this

. provision be used repeatedly as a convenience to extend the surveillance intervals beyond that specified for surveillances that are not perfonned during refueling outages. The limitation of Specification 4.0.2 is based on engineering judgment and the recognition that the most probable result of any particular surveillance being performed is the verification of conformance with the Surveillance Requirements. This provision is sufficient to ensure i

that the reliability ensured through surveillance activities is not significantly degraded beyond that obtained from the specified surveillance interval.

Specification 4.0.3 establishes the failure to perform a Surveillance Requirement within the allowed surveillance interval, defined by the provisions of Specification 4.0.2, as a condition that constitutes a failure to meet the operability requirements for a Limiting Condition for Operation.

Under the provisions of this specification, systems and components are assumed to be operable when Surveillance Requirements have Amendment No. HO, MB,171 4-3

4.1 DVERPRESSURE PROTECTION SYSTEM TESTS Surveillance Reouiraments In addition to the requirements of Specification 4.0.E, each PORV flow path shall be demonstrated OPERABLE by:

1.

Testing the PORVs in accordance with the inservice inspection requirements for ASME Boiler and Pressure Vessel Code,Section XI, Section IWV, Category B valves.

2.

Performance of a CHANNEL CALIBRATION on the PORV actuation channel at least once per 18 months.

l 3.

When the PORV flow path is required to be OPERABLE by Specification 3.1.8.1:

l (a) Performing a complete cycle of the PORV with the plant above COLD SHUTDOWN at least once per 18 months.

l (b)

Performing a complete cycle of the block valve prior to heatup from COLD SHUTDOWN, if not cycled within 92 days.

4.

When the PORY flow path is required to be OPERABLE by Specification 3.1.8.2:

(a) Performance of a CHANNEL FUNCTIONAL TEST on the PORV actuation i

channel, but excluding valve operation, at least once per 31 j

days.

(b) Verifying the associated block valve is open at least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

l 5.

Both High Pressure Safety Injection pumps shall be verified incapable of injection into the PCS at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, i

unless the reactor head is removed, when either PCS cold leg l

temperature is <300*F, or when both shutdown cooling suction valves, M0-3015 and M0-3016, are open.

t i

Basis With the reactor vessel head installed when the PCS cold leg temperature is less than 300*F, or if the shutdown cooling system isolation valves M0-3015 and MO-3016 are open, the start of one HPSI pump could cause the Appendix G or the shutdown cooling system pressure limits to be exceeded; therefore, both pumps are rendered inoperable.

Amendment No. MG, H9, MG, MB, MB, M4,171 4-6

4.14 AUGMENTED INSERVICE INSPECTION PROGRAM FOR STEAM GENERATORS (Cont'd) 7.

Unserviceable described the condition of a tube if it leaks or i

contains a defect large enough to affect its structural integrity in the event of an Operating Basis Earthquake, a loss-of-coolant accident, or a steam line or feedwater line break as specified in 4.14.4.c, above.

l 8.

Tube Insnection means an inspection of the ; team generator tube from the point of entry (hot leg side) completely around the U-bend to the top support of the cold leg.

9.

Preservice Insnection means an inspection of the full length of each tube in steam generator performed by eddy current techniques prior to service to establish a baseline condition of the tubing.

This inspection shall be performed after the shop hydrostatic test and prior to initial POWER OPERATION using the equipment and techniques expected to be used during subsequent inservice inspections, b.

The steam generator shall be determined OPERABLE after completing the 3

corresponding actions (plug all tubes exceeding the plugging limit and all tubes containing through-wall cracks) required by Table 4.14-2.

l 4.14.6 Renorts l

l a.

Within 15 days following the completion of each inservice inspection of steam generator tubes, the number of tubes plugged in each steam generator shall be reported to the Commission in a Special Report i

l pursuant to 10 CFR 50.4.

b.

The complete results of the steam generator tube inservice inspection l

shall be submitted to the Commission in a Special Report pursuant to l

l 10 CFR 50.4 within 12 months following completion of the inspection.

l This Special Report shall include:

l 1.

Number and extent of tubes inspected.

i 2.

Location and percent of wall-thickness penetration for each indication of an imperfection.

l 3.

Identification of tubes plugged Results of steam generator tube inspections that fall into Category C-3 c.

shall require 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> verbal notification to the NRC prior to resumption of plant operation. A written followup within the next 30 days shall provide a description of investigations and corrective measures taken to prevent recurrence.

i l

4-69 l

Amendment No. 39, 60, 406, 440, 43B, 444, i

171

4.16 INSERVICE INSPECTION PROGRAM FOR SHOCK SUPPRESSORS (Snubbers) 4.16.1 b.

Visual Insoection Accentance Criteria (continued)

A review and evaluation shall be performed and documented to justify continued operation with an unacceptable snubber.

If continued operation cannot be justified, the snubber shall be declared inoperable and the action requirements shall be met.

l c.

Functional Tests i

At least once per 18 months during shutdown, a representative sample (10% of the total safety-related snubbers in use at the plant) shall be functionally tested either in place or in a bench test. The test shall I

verify the snubber has freedom of movement and is not frozen up. For each snubber which did not meet the functional test acceptance criteria of Specification 4.16.1.d or 4.16.1.e, an additional 10% of the total shall be functionally tested."3 The representative sample selected for functional testing shall include the various configurations, operating environments and the range of size and capacity of snubbers. Snubbers identified as especially difficult to remove or in high radiation zones during shutdown shall also be included in the representative sample.i2>

In addition to the regular sample, snubbers which failed the previous functional test shall be retested during the next test period.

If a spare snubber has been installed in place of a failed snubber, then both the failed snubber (if it is repaired and installed in another position) and the spare snubber shall be retested. Test results of these snubbers may not be included for the resampling.

If any snubber selected for functional testing either fails to lockup or fails to move, i.e., frozen in place, the cause will be evaluated and, if caused by manufacturer or design deficiency, all snubbers of the same design subject to the same defect shall be functionally tested. This testing requirement shall be independent of the requirements stated above for snubbers not meeting the functional test acceptance criteria.

' Snubbers of rated capacity greater than 50,000 pounds are not to be included when defining the total number of safety-related snubbers in use at the plant.

Permanent or other exemptions from functional testing for individual snubbers may be granted by the Commission only if a justifiable basis for exemption is presented and/or snubber life destructive testing was performed to qualify snubber operability for all design conditions at either the completion of their fabrication or at a subsequent date.

4-72 Amendment No. 448, M4,171

4.16 INSERVICE INSPECTION PROGRAM FOR SHOCK SUPPRESSORS (Snubbers) 4.16.1 c.

Functional Tests (continued) l Snubbers of rated capacity greater than 50,000 pounds will be functionally tested in lots comprising 25% of their total during each refueling outage.

In the event of one snubber failure out of the four tested, no additional snubbers will be tested provided the problem is non-generic.

For each additional snubber failure, however, two additional. snubbers will be tested until no further snubber failures are identified or all snubbers have been tested.

Generic failures will be handled as the specific circumstances require.

For the snubber (s) found inoperable, an engineering evaluation shall'be performed on the components which are suppressed by the snubber (s).

The purpose of this engineering evaluation shall be to determine if the components suppressed by the snubber (s) were adversely affected by the inoperability of the snubber (s) in order to ensure that the suppressed component remains capable of meeting the designed service.

d.

Hydraulic Snubbers Functional Test Accentance Criteria The hydraulic snubber functional test shall verify tLat:

1.

Activation (restraining action) is_ achieved within the specified range of velocity or acceleration in both tension and compression.

2.

Snubber bleed, or release rate, where required, is within the specified range in compression or tension.

For snubbers specifically required not to displace under continuous load, the ability of the snubber to withstand load without displacement shall be verified.

e.

Mechanical Snubbers Functional Test Acceotance Criteria The mechanical snubber functional test shall verify that:

1.

The force that initiates free movement of the snubber rod in either tension or compression is less than the specified maximum drag force (break away friction).

2.

Activation (restraining action) is achieved within the specified range of velocity or acceleration in both tension and compression.

3.

Snubber release rate, where required, is within the specified range in compression or tension.

For snubbers specifically required not to displace under continuous load, the ability of the snubber to withstand load without displacement shall be verified.

4-73 Amendment No. M, 69, M7, M4,171

t 4.17 INSTRUMENTATION SYSTEMS TESTS Table 4.17.1 Instrumentation Surveillance Reauirements for Reactor Protective System CHANNEL 4

CHANNEL FUNCTIONAL CHANNEL j

Functional Unit CHECK TEST CALIBRATION i

1.

. Manual Trip NA (a)

NA 2.

Variable High Power 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days (b, c, & d) 3.

High Start Up Rate 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (a) 18 months

l 4.

Thermal Margin /

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months Low Pressure

.a j

l 5.

High Pressurizer 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months Pressure j

l 6.

Low PCS Flow 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months 7.

Loss of Load NA (a) 18 months l 8.

Low "A" SG Level 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months l 9.

Low "B" SG Level 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months l 10. Low "A" SG Pressure 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months l 11.

Low "B" SG Pressure 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months

12. - High Containment Pressure NA 31 days 18 months

13. RPS Matrix Logic NA 31 days NA 14.

RPS Initiation Logic NA 31 days NA

15. Thermal Margin Monitor; Verify constants each 92 days.

(a) Once within 7 days prior to each reactor startup.

(b) Calibrate with Heat Balance each 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, when > 15% RATED POWER.

(c)

Calibrate Excores channels with test signal each 31 days.

(d) CHANNEL CALIBRATION each 18 months.

(e)

Include verification of automatic Zero Power Mode Bypass removal.

Amendment No. M8, MG, M6, MO, M3, M4,171 4-76

O 4.17 INSTRUMENTATION SYSTEMS TESTS Table 4.17.2 Instrumentation Surveillance Reauirements for Enaineered Safety Features CHANNEL CHANNEL FUNCTIONAL CHANNEL Functional Unit CHECK TEST CALIBRATION 1.

Safety Iniection Sianal (SIS) a.

Manual Initiation NA 18 months NA b.

SIS Logic NA (a)

NA (Initiation, Actuation, and low pressure block auto reset) c.

CHP Signal SIS initiation NA 18 months NA (SP Relay Output) d.

Pressurizer Pressure 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months l

Instrument Channels 2.

Recirculation Actuation Sianal (RAS) a.

Manual Initiation NA 18 months NA b.

RAS Logic NA 18 months NA c.

SIRWT Level Switches NA 18 months 18 months l

3.

Auxiliary Feedwater Actuation Sianal (AFAS) a.

Manual Initiation NA 18 months NA b.

AFAS Logic NA 92 days NA c.

"A" SG Level 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months l

d.

"B" SG Level 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months l

4.

Emeroency Power Seouencers a.

DBA Sequencer NA 92 days 18 months i

b.

Normal Shutdown Sequencer NA 18 Months 18 months (a) Test normal and emergency power functions using test circuits each 92 days.

Verify all automatic actuations and automatic resetting of low pressure block each 18 months.

Amendment No. MB, M4,171 4-77

T 4.17 INSTRUMENTATION SYSTEMS TESTS Table 4.17.3 Instrumentation Surveillance Reauirements for Isolation Functions CHANNEL CHANNEL FUNCTIONAL CHANNEL Functional Unit CHECK TEST CALIBRATION

1. Containment Hiah Pressure (CHP)

a. CHP logic Trains NA 18 months NA

b. Cantainment Pressure NA 31 days 18 months Switches - Left Train

c. Containment Pressure NA 31 days 18 months Switches - Right Train

2. Containment Hich Radiation (CHR)

a. Manual Initiation 1*.

9 months NA

b. CHR Logic Trains NA IG months NA l

c. Containment Area 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />

• !! days 18 months Radiation Monitors

3. Steam Generator low Pressure (SGLP)

a. Manual Actuation NA 18 months NA

b. SGLP Logic Trains NA 18 months NA l

c. "A" Steam Generator 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months l

Pressure l

d. "B" Steam Generator 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months Pressure

4. Enaineered Safeauards Pemo Room Hiah Radiation a.

East Room Monitor 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months i

b.

West Room Monitor 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months I

Amendment No. MB, M4,171 4-78 I

w 4.17 INSTRUMENTATION SYSTEMS TESTS Table 4.17.4 Instrumentation Strveillance Reauirements for Acc< c enn Pbnitorina CHANNEL CHANNEL i

Instrument CHECK CALIBRATION 1.

Wide Range Tg 31 days 18 months 2.

,ide Range Tc 31 days 18 months W

3.

Wide Range Flux 31 days 18 months 4.

Containment Floor Water Level 31 days 18 months 5.

Subcooled Margin Monitor 31 days 18 months l

6.

Wide Range Pressurizer Level 31 days 18 months 7.

Containment H Concentration 31 days 18 months 2

8.

Condensate Storage Tank Level 31 days 18 months 9.

Wide Range Pressurizer Pressure 31 days 18 months l

10. Wide Range Containment Pressure 31 days 18 months

11. Wide Range "A" SG Level 31 days 18 months l

12. Wide Range "B" SG Level 31 days 18 months l

13. Narrow Range "A" SG Pressure 31 days 18 months l

l

14. Narrow Range "8" SG Pressure 31 days 18 months l

15.

Position Indication for each 31 days 18 months Containment Isolation Valve 16.

Core Exit Thermocouples (CET) 31 days 18 months"'

Quadrant 1 17.

Core Exit Thermocouples (CET) 31 days 18 months"'

l Quadrant 2 l

18.

Core Exit Thermocouples (CET) 31 days 18 months"*

i Quadrant 3 19.

Core Exit Thermocouples (CET) 31 days 18 months

Quadrant 4 20.

Reactor Vessel Water Level (RVWL) 31 days 18 months 21.

High Range Containment Radiation 31 days 18 months l

(a)

Calibrate by substituting a known voltage for thermocouple.

4 Amendment No. 462, 464,171 4-79 l

]

4.17 INSTRUMENTATION SYSTENS TESTS Table 4.17.5 Instrumenta". ion Surveillance Reauirements for A' terna';e Shutdown Sys' em CHANNEL CHANNEL FUNCTIONAL CHANNEL Instrument or Control CHECK TEST CALIBRATION 1.

Start-up Range Flux (a)

(a) 18 months l 2.

Pressurizer Pressure 92 days NA 18 months 3.

Pressurizer Level 92 days NA 18 months 4.

1. 1 Hot Leg Temperature 92 days NA 18 months 5.

1. 2 Hot Leg Temperature 92 days NA 18 months 6.

1. 1 Cold Leg Temperature 92 days NA 18 months 7.

1. 2 Cold Leg Temperature 92 days NA 18 months l 8.

"A" SG Pressure 92 days NA 18 months l 9.

"B" SG Pressure 92 days NA 18 months l 10.

"A" SG Level 92 days NA 18 months l 11.

"B" SG Level 92 days NA 18 months

12. SIRW Tank Level 92 days NA 18 months 13.

P-88 Flow to "A" SG 18 months 18 months 18 months 14.

P-88 Flow to "B" SG 18 months 18 months 18 months 15.

P-8B Low Suction Alarm NA 18 months 18 months 16.

P-8B Steam Valve Control NA 18 months NA

17. AFW Flow Control "A" SG NA 18 months NA

18. AFW Flow Control "B" SG NA 18 months NA

19. Transfer Switches, C-150 NA 18 months NA

20. Transfer Switch, C-150A NA 18 months NA i

(a) Once within 7 days prior to each reactor startup.

Amendment No. MB, +M, MB, M4,171 4-80

l 4.17' INSTRUMENTATION SYSTEMS TESTS Table 4.17.6 Instrumentatic n Surveilla nee Reauirements for Ot ier Safety

unctions 1

CHANNEL i

CHANNEL FUNCTIONAL CHANNEL Instrument CHECK TEST CALIBRATION 1.

Neutron Flux Monitoring 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (a) 18 months 2.

Rod Position Indication 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> (b) 18 months 3.

SIRW Tank Temperature 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> NA 18 months 4.

Main Feedwater Flow 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Not Required 18 months l

5.

Main Feedwater Temp.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Not Required 18 months l

6.

AFW Flow Indication 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 18 mont'hs 18 months 7.

PCS Leakage Detection:

a.

Sump Level 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 18 months 18 months b.

Atmos. Gas Monitor 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 18 months 18 months c.

Humidity Monitor 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 18 months 18 months l

d.

Air Cooler Condensate NA 18 months Not Required Flow Switch 8a.

Primary Safety Valve NA 18 months 18 months acoustical monitor 8b/ Safety Valve / PORV"'

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 18 months 18 months 9a. tailpipe temperature 9b.

PORV Acoustical Monitor NA 18 months 18 months 9c.

PORY Sten Position 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 18 months 18 months 10.

PORV Block Valve 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> NA 18 months Position Indication (a) Once within 7 days prior to each reactor startup.

(b) Verification of Regulating Rod Withdrawal and Shutdeun Rod Insertion interlocks OPERA 8ILITY only, once within 92 days prior to each reactor startup AND once prior to startup after each refueling.

(c) The tailpipe temperature indicator is common to the safety valves and PORVs (continued)

Amendment No. MB, M4,171 4-81

i

,s l

4.17 INSTRUMENTATION SYSTEMS TESTS Table 4.17.6 (continued)

Instrumentatirn Surveillance Reauirements for Ot ier Safety unctions l

CHANNEL l

CHANNEL FUNCTIONAL CHANNEL Instrument CHECK TEST CALIBRATION

11. SWS Break Detector NA 18 months 18 months j

12. Flux - AT Comparator 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 31 days 18 months 13.

Rod Group Sequence NA 18 months 18 months Control / Alarm

14. BAT Low Level Alarm NA 18 months Not Required

15. Excore Deviation Alarm NA 18 months 18 months

16. ASI Alarm NA 18 months 18 months l 17. SDC Suction Interlocks NA 18 months 18 months

18. PDIL Alarm NA 31 days" 18 months

19. Fuel Pool Rad Monitor 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 31 days 18 months

20. Containment Refueling 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 31 days 18 months Radiation Monitor (d) Setpoint verification only.

Amendment No. MB, M4,171 4-82

,w i

5.3 NUCLEAR STEAM SUPPLY SYSTEM (NSSS). (Continued) 5.3.2 Reacton Core and Control The reactor core shall approximate a right circular cylinder with a.

an equivalent diameter of about 136 inches and an active height of about 132 inches.

b.

The reactor core shall consist of approximately 43,000 Zircaloy-4 clad fuel rods containing depleted, natural, or slightly enriched uranium in the form of sintered U0, pellets. The fuel rods shall be grouped into 204 assemblies. A core plug or plugs may be used to replace one or more fuel assemblies subject to the analysis of the resulting power distribution.

The fully loaded core shall contain asproximately 211,000 pounds c.

UO.and approximately 56,000 pounds of Zircaloy-4.

Poison ma placed in the fuel bundles for long-term reactivity control. y be 2

d.

The core excess reactivity shall be controlled by a combination of boric acid chemical shim, cruciform control rods, and mechanically fixed absorber rods where required. Forty-five control rods shall be distributed throughout the core as shown in Figure 3-2 of the FSAR.

Four of these control rods may consist of part-length absorbers.

5.3.3 Emeraency Core Coolina System An emergency core cooling system shall be installed' consisting of various subsystems each with internal redundancy. These subsystems shall include four safety injection tanks, two high-pressure and two low-pressure safety injection pumps, a safety injection and refneling water storage tank, and interconnecting piping as shown in Section 6 of the FSAR.

i 5-3 Amendment No. N, 49, 83, M6,171

-