ML13316B224

Amend 117 to License DPR-13,approving Installation of Upgraded Nuclear Instrumentation Sys,Together W/Modified Limiting Conditions for Operation & Surveillance Requirements in Tech Specs for Upgraded Sys

ML13316B224
Person / Time
Site:	San Onofre
Issue date:	12/13/1988
From:	Knighton G Office of Nuclear Reactor Regulation
To:
Shared Package
ML13316B223	List: ML13316B222 ML13316B224 ML13316B226 ML13316B228
References
DPR-13-A-117 NUDOCS 8812280235
Download: ML13316B224 (29)

Text

UNITED-STATES

,A "NUCLEAR REGULATORY'COMMISSION WASHINGTON, D. C. 20555 SOUTHERN CALIFORNIA EDISON COMPANY SAN DIEGO GAS AND ELECTRIC COMPANY DOCKET NO. 50-206 SAN-ONOFRE NUCLEAR GENERATING STATION, UNIT NO. 1 AMENDMENT TO PROVISIONAL OPERATING LICENSE Amendment No. 117 License No. DPR-13

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

A. The application for amendment by Southern California Edison Company and San Diego Gas and Electric Company (the licensee) dated April 15, 1988, as supplemented October 18 and 21, and November 10, 19 and 23 (2 letters), 1988 complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's 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 regulations of the Commission; C. There is reasonable assurance (i) 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; and 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.

8812260235 881213 PDR ADOCK 05000206 P

PNU

-2

2. Accordingly, the license is amended by changes to the Technical Speci fications as indicated in the attachment to this license amendment, and paragraph 3.B. of Provisional Operating License No. DPR-13 is hereby amended to read as follows:

B. Technical Specifications The Technical Specifications contained in Appendix A, as revised through Amendment No. 117, are hereby incorporated in the license. Southern California Edison Company shall operate the facility in accordance with the Technical Specifications, except where otherwise stated in specific license conditions.

3. This license amendment is effective as of the date of its issuance and must be fully implemented no later than 30 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION v George W. Knighton, Director Pkoject Directorate V Division of Reactor Projects -

III, IV, V and Special Projects

Attachment:

Changes to the Technical Specifications Date of Issuance:

December 13, 1988

ATTACHMENT TO LICENSE AMENDMENT NO.117 PROVISIONAL OPERATING LICENSE NO. DPR-13 DOCKET NO. 50-206 Revise Appendix A Technical Specifications by removing the pages identified below and inserting the enclosed pages. The revised pages are identified by the captioned amendment number and contain marginal lines indicating the area of change.

REMOVE INSERT 1

1 la la lb lb 1c 1c 1d 1d le le if 1g 2-2 3

3 4

4

.5 5

28 28 29 29 30 30 30a 30a 30b 33o 33o 39c 39c 39d 39d 40b 40b (next page is Table 4.1.1 marked page 4-1a) 4-la (next page is marked 4-2) 4-2 41 41 42 42 42a 43 43 43e 44g 44g 53a 53a

1.0 DEFINITIONS The defined terms of this section appear in capitalized type and are applicable throughout these Technical Specifications-.

ACTION 1.1 ACTION shall be that part of a Specification which prescribes remedial measures required under designated conditions.

ACTUATION LOGIC TEST 1.2 An ACTUATION LOGIC TEST shall be the application of various simulated input combinations in conjunction with each possible interlock logic state and verification of the required logic output. The ACTUATION LOGIC TEST shall include a continuity check, as a minimum, of output devices..

CHANNEL CALIBRATION 1.3 A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel such that it responds with the required range and accuracy to known values of input. The CHANNEL CALIBRATION shall encompass the entire channel including the sensors and alarm, interlock and/or trip functions and may be performed by any series of sequential, overlapping, or total channel steps such that the entire channel is calibrated.

CHANNEL CHECK 1.4 A CHANNEL CHECK shall be the qualitative assessment of channel behavior during operation by observation.- This determination shall include, where possible, comparison of the channel indication and/or status with other indications and/or status derived from independent instrument channels measuring the same parameter.

CHANNEL TEST 1.5 A CHANNEL TEST shall be the injection 'f a simulated signal into the channel to verify its proper response including, where applicable, alarm and/or trip initiating action. The CHANNEL TEST shall include adjustments, as necessary, of the alarm, interlock and/or trip setpoints, such that the setpoints are within the required range and accuracy.

CONTAINMENT INTEGRITY 1.6 CONTAINMENT INTEGRITY shall exist when:

(1) All non-automatic containment isolation valves (or blind flanges) are closed.

Amendment No.

YV, 6.59.,117

0a (2) The equipment door is properly closed.

(3) At least one door in each personnel air lock is properly closed.

(4) All automatic containment isolation valves are operable.

CORE ALTERATION 1.7 CORE ALTERATION shall be the movement or'manipulation of any component within the.reactor pressure vessel with the vessel head removed and fuel in the vessel.

Suspension of CORE ALTERATION shall not preclude completion of movement of a component to a safe conservative position.

CORRELATION CHECK 1.8 A CORRELATION CHECK shall be an~engineering analysis of an incore flux map wherein at least one point along the incore versus excore correlation data plot is obtained.

CORRELATION VERIFICATION 1.9 A CORRELATION VERIFICATION shall be the engineering analysis of incore flux maps wherein multiple points along the incore versus excore correlation data plot are obtained.

DG FAST START 1.9.1 DG FAST START shall be an automatic or manual start of an emergency diesel generator in which the steady state voltage and frequency is achieved within 10 seconds.

DG SLOW START 1.9.2 DG SLOW START shall be an automatic or manual start of an emergency diesel generator in which steady state voltage and frequency is achieved in not less than 24 seconds.

DOSE EQUIVALENT 1-131 1.10 DOSE EQUIVALENT I-131 shall be that concentration of 1-131 (microcurie/gram) which alone would produce the same thyroid dose as the quantity and isotopic mixture of I-131, 1-132, 1-133, 1-134, and 1-135 actually present. The thyroid dose conversion factors used for this calculation shall be those listed in Table III of TID-14844, "Calculation of Distance Factors for Power and Test React6r Sites."

E - AVERAGE DISINTEGRATION ENERGY 1.11 E is the average (weighted in proportion to the concentration of each radionuclide in the reactor coolant at the time of sampling) of the sum of the average beta and gamma energies per disintegration (in MeV) for isotopes, other than iodines and tritium with half lives greater than 15 minutes, making up at least 95% of the total non-iodine and non-tritium activity in the coolant.

Amendment No. 37,,979.22 704 1

lb FIRE SUPPRESSION WATER SYSTEM 1.12 A FIRE SUPPRESSION WATER SYSTEM shall consist of a water source(s), pump(s), and distribution piping with associated isolation valves (i.e., system header, hose standpipe and spray header isolation valves).

FREQUENCY NOTATION 1.13 The FREQUENCY NOTATION specified for the performance of Surveillance Requirements shall correspond to the intervals defined in Table 1.1.

GASEOUS RADWASTE TREATMENT SYSTEM 1.14 A GASEOUS RADWASTE TREATMENT SYSTEM is any system designed and installed to reduce radioactive gaseous effluents by collecting primary coolant system offgases from the primary system and providing for delay or holdup for the purpose of reducing the total radioactivity prior to release to the environment.

MEMBER(S) OF THE PUBLIC 1.15 MEMBER(S) OF THE PUBLIC shall include all individuals who by virtue of their occupational status have no formal association with the plant. This category shall include nonemployees of the licensee who are permitted to use portions of the site for recreational, occupa tional, or purposes not associated with plant functions. This category shall not include nonemployees such as vending machine servicemen or postmen who, as part of their formal job function, occasionally enter an area that is controlled by the licensee for purposes of protection of individuals from exposure to radiation and radioactive materials.

OFFSITE DOSE CALCULATION MANUAL (ODCM) 1.16 An OFFSITE DOSE CALCULATION MANUAL (00CM) shall contain the current-methodology and parameters used in the calculation of offsite doses due to radioactive gaseous and liquid effluents, in the calculation of gaseou-s and liquid effluent monitoring alarm/trip setpoints, and in the conductof the environmental radiological monitoring program.

OPERABLE - OPERABILITY 1.17 A system, subsystem, train, component or device shall be OPERABLE or have OPERABILITY when it is capable of performing its specified function(s), and when all necessary attendant instrumentation, controls, electrical power, cooling or seal water, lubrication or other auxiliary equipment that are required for the system, subsystem, train, component, or device to perform its function(s) are also capable of performing their related support function(s).

Amendment No.

7

IC OPERATIONALMODE - MODE 1.18 An OPERATIONAL MODE (i.e., MODE) shall correspond to any one inclusive combination of core reactivity condition, power level, and average reactor coolant temperature specified in Table 1.2.

PROCESS CONTROL PROGRAM 1.19 The PROCESS CONTROL PROGRAM shall contain the current formula, sampling, analysis,' and formulation determination by which SOLIDIFI CATION of radioactive wastes from liquid systems is assured.

PURGE-PURGING 1.20 PURGE or PURGING is the controlled process of discharging air or gas from a confinement to maintain temperature,'pressure, humidity, concentration or other operating condition, in such a manner that replacement air or gas is required to purify the confinement.

RATED THERMAL POWER 1.21 RATED THERMAL POWER shall be a total reactor core heat transfer rate to the reactor coolant of 1347 Mwt.

REPORTABLE EVENT 1.22-A REPORTABLE EVENT shall be any of those conditions specified in Section 50.73 to 10 CFR Part 50.

RESIDUAL HEAT REMOVAL (RHR) TRAIN 1.23 An RHR TRAIN shall be a train of components that includes:

one RHR pump aligned with one RHR heat exchanger; one component cooling water pump aligned with the same RHR heat exchanger and with one component cooling water heat exchanger; and one salt water pump aligned with the same component cooling water heat exchanger.

SHUTDOWN MARGIN 1.24 SHUTDOWN MARGIN shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming all rod cluster assemblies (shutdown and control) are fully inserted except for the single rod cluster assembly of highest reactivity worth which is assumed to be fully withdrawn.

SITE BOUNDARY 1.25 The SITE BOUNDARY shall be that line beyond which the land is not owned, leased, or otherwise controlled by the licensee.

SOLIDIFICATION 1.26 SOLIDIFICATION shall be the conversion of wet wastes into a form that meets shipping and burial ground requirements.

Amendment No. 177,9,8,9,117

1 d SOURCE CHECK 1.27 A SOURCE CHECK is the qualitative assessment of a channel response when the channel sensor is exposed to a radioactive source.

STAGGERED TEST BASIS 1.28 A STAGGERED TEST BASIS shall consist of:

a. A test schedule for n systems, subsystems, trains, or other designated components obtained by dividing the specified test interval into n equal subintervals,

b. The testing of one system, subsystem, train, or other designated component at the beginning of each subinterval.

THERMAL POWER 1.29 THERMAL POWER shall be the total reactor core heat transfer rate to the reactor coolant.

TRIP ACTUATING DEVICE OPERATIONAL TEST 1.30 A TRIP ACTUATING DEVICE OPERATIONAL TEST shall consist of operating the Trip Actuating Device and verifying OPERABILITY of alarm, interlock and/or trip functions. The TRIP ACTUATING DEVICE OPERATIONAL TEST shall include adjustment, as necessary, of the Trip Actuating Device such that it actuates at the required setpoint within the required accuracy.

UNRESTRICTED AREA 1.31 An UNRESTRICTED AREA shall be any area at or beyond the SITE BOUNDARY access to which is not controlled by the licensee for purposes of protection of individuals from exposure to radiation and radioactive materials or any area within the site boundary used for residential quarters or industrial, commercial, institutional and/or recreational purposes.

VENTILATION EXHAUST TREATMENT SYSTEM 1.32 A VENTILATION EXHAUST TREATMENT SYSTEM is any system designed and installed to reduce gaseous radioiodine or radioactive material in particulate form in effluents by passing ventilation or vent exhaust gases through charcoal absorbers and/or HEPA filters for the purpose of removing iodines or particulates from the gaseous exhaust'stream prior to the release to the environment. Such a system.is not considered to have any effect on noble gas effluents. Engineered Safety Feature (ESF) atmospheric cleanup systems are not considered to be VENTILATION EXHAUST TREATMENT SYSTEM components.

VENTING 1.33 VENTING is the controlled process of discharging air or gas from a confinement to maintain temperature, pressure, humidity, concentra Amendment No. 7

le tion or other.operating condition, in such a manner that replacement air or gas is not provided or required during VENTING. Vent, used in system names, does not imply a VENTING process.

Amendment No.. 117

-If TABLE 1.1 FREQUENCY NOTATION NOTATION FREQUENCY S

At least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

0 At least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

W At least once per 7 days.

B W At least once per 14 days.

M At least once per 31 days.

Q At least once per 92 days.

SA At least once per 184 days.

R At least once per 18 months.

S/U Prior to each reactor startup.

P

.Completed prior to each release.

N/A Not applicable.

Amendment No. 50,117

TABLE 1.2 OPERATIONAL MODE REACTIVITY

% RATED AVERAGE COOLANT MODE CONDITION. Keff THERMAL POWER*

TEMPERATURE

1. POWER OPERATION

>0.99

>5%

>350oF

2. STARTUP

?0.99

<5%

>350oF

3. HOT STANDBY

<0.99 0

>350oF

4.

HOT SHUTDOWN

<0.95 0

350oF>Tavg>200OF

5. COLD SHUTDOWN g0.95 0

<S200oF

6. REFUELING**

50.95 0

<1400F

• Excluding decay heat

• • Reactor vessel head unbolted or removed and fuel in the vessel.

Amendment No.

0,83.117

2 2.1 REACTOR CORE -

Limiting Combination of Power, Pressure, and Temperature APPLICABILITY: Applies to reactor power, system pressure, coolant temperature, and flow during operation of the plant.

OBJECTIVE:

To maintain the integrity of the reactor coolant system and to prevent the release of excessive amounts of fission product activity to the coolant.

SPECIFICATION: Safety Limits (1) The reactor coolant system pressure shall not exceed 2735 psig with fuel assemblies in the reactor.

(2) The combination of reactor power and coolant tefperature shall not exceed the locus of points established for the RCS pressure in Figure 2.1.1. If the actual power and temperature is above the locus of points for the appropriate RCS pressure, the safety limit is exceeded.

Maximum Safety System Settings The maximum safety system trip settings shall be as stated in Table 2.1 BASIS:

Safety Limits

1. Reactor Coolant System Pressure The Reactor Coolant System serves as a barrier which prevents release of radionuclides contained in the reactor coolant to the containment atmosphere. In addition, the failure of components of the Reactor Coolant System could result in damage to the fuel and pressurization of the containment. A safety limit of 2735 psig (110% of design pressure) has-been established which represents the maximum transient pressure allowable i*n the -Reactor Coolant System under the ASME Code,Section VIII.

2. Plant Operating Transients In order to prevent any significant amount of fission products from being released from the fuel to the reactor coolant, it is necessary to prevent clad overheating both during normal operation and while undergoing system transients. Clad overheating and potential failure could occur if the heat transfer mechanism at the clad surface departs from nucleate boiling. System-parameters which affect this departure from nucleate boiling (DNB) have been correlated with experimental data to provide a means of determining the probability of DNB occurrence. The ratio of the heat flux at which DNB is expected to occur for a given set of conditions to the actual heat flux experienced at a point is the DNB ratio and reflects the probability that DNB will actually occur.

Amendment No. M00,07.117

It has been determined that under the most unfavorable conditions of power distribution expected during core lifetime and if a DNB ratio of 1.44 should exist, not more than 7 out of the total of 28,260 fuel rods would be expected to experience DNB. These conditions correspond to a reactor power of 125% of rated power. Thus, with the expected power distribution and peaking factors, no significant release of fission products to the reactor coolant system should occur at DNB ratios greater than 1.30.(1)

The DNB ratio, although fundamental, is not an observable variable. For this reason, limits have been placed on reactor.coolant temperature, flow, pressure, and power level, these being the observable process variables related to determination of the DNB ratio. The curves presented in Figure 2.1.1 represent loci of conditions at which a minimum DNB ratio of 1.30 or greater would occur. (1)(2)(3)

Maximum Safety System Settings

1. Pressurizer Hiah Level and High Pressure In the event of loss, of load, the temperature and pressure of the Reactor Coolant System would increase since there would be a large and rapid reduction in the heat extracted from the Reactor Coolant System through the steam generators. The maximum settings of the pressurizer high level trip and the pressurizer high pressure trip are established to maintain the DNB ratio above 1.30 and to prevent the loss of the cushioning effect of the steam volume in the pressurizer (resulting in a solid hydraulic system) during a loss-of-load transient.( 3)(4)

In the event that steam/feedflow mismatch trip cannot be credited due to single failure considerations, the pressurizer high level trip is provided. In order to meet acceptance criteria for the Loss of Main Feedwater and Feedline Break transients, the pressurizer high level trip must be set at 20.8 ft. (50%) or less.

2. Variable Low Pressure. Loss of Flow. and Nuclear Overpower These settings are established to accommodate the most severe transients upon which the design is based, e.g., loss of coolant flow, rod withdrawal at power, control rod ejection, inadvertent boron dilution and large load increase.without exceeding the safety limits.

The settings have been derived in consideration of instrument errors and response times of all necessary equipment.

Thus, these settings should prevent the release of any significant quantities of fission oroducts to the coolant as a result of transients.(3)(4)(5)(7)

Amendment No. 4,117

4 In order to prevent significant fuel damage in the event of increased peaking factors due to an asymmetric power distribution in the core, the nuclear overpower trip setting on all channels is reduced by one percent for each percent that the asymmetry in power distribution exceeds 5%. This provision should maintain the DNB ratio above a value of 1.30 throughout design transients mentioned above.

The response of the plant to a reduction in coolant flow while the reactor is at substantial power is a corresponding increase in reactor coolant temperature. If the increase in temperature is large enough, DNB could occur, following loss of flow.

The low flow signal is set high enough to actuate a trip in time to prevent excessively high temperatures and low enough to reflect that a loss of flow conditions exists.

Since coolant loop flow is either full on or full off, any loss of flow would mean a reduction of the initial flow (100%) to zero.(3)(6)

References:

(1) Amendment No. 10 to the Final Engineering Report and Safety Analysis, Section 4, Question 3 (2) Final Engineering Report and Safety Analysis, Paragraph 3.3 (3) Final Engineering Report and Safety Analysis, Paragraph 6.2 (4) Final Engineering Report and Safety Analysis, Paragraph 10.6 (5) Final Engineering Report and Safety Analysis, Paragraph 9.2 (6) Final Engineering Report and Safety Analysis, Paragraph 10.2 (7) NIS Safety Review' Report, Apfil 1988 Amendment No. 97,117

0 5

TABLE 2.1 MAXIMUM SAFETY SYSTEM SETTINGS Three Reactor Coolant Pumps ODerating

• 1. Pressurizer

< 20.8 ft. above bottom of pressurizer High Level when steam/feedflow mismatch trip is not credited, or

< 27.3 ft. above bottom of pressurizer when steam/feedflow mismatch trip 1ij credited

2. Pressurizer

< 2220 psig Pressure:

High

3. Nuclear Overpower

a.

High Setting**

< 109% of indicated full power

b.

Low Setting i 25% of indicated full power

• • 4.

Variable Low Pressure

> 26.15 (0.894 AT+T avg.) -

14341

• • • 5.

Coolant Flow 2 85% of indicated full loop flow Credit can be taken for the steam/feedflow mismatch trip when this system is modified such that a single failure will not prevent the system from performing its safety function.

The nuclear overpower trip high setting is based upon a symmetrical power distribution. If an asymmetric power distribution greater than 5% should occur, the nuclear overpower trip on all channels shall be reduced one percent for each percent above 5%.

• • • May be bypassed at power levels below 10% of full power.

Amendment No. 117

28 3.5 INSTRUMENTATION AND CONTROL 3.5.1 REACTOR TRIP SYSTEM INSTRUMENTATION APPLICABILITY:

As shown in Table 3.5.1-1.

OBJECTIVE:

To delineate the conditions of the plant instrumentation and safety circuits necessary to ensure reactor sa-fety.

SPECIFICAION:

As a minimum, the reactor trip system instrumentation channels and interlocks of Table 3.5.1-1 shall be OPERABLE.

ACTION:

As shown in Table 3.5.1-1.

BASIS:

During plant operations, the complete instrumentation systems will normally be in service.(l)

Reactor safety is provided by the Reactor Protection System, which automatically initiates appropriate action to prevent exceeding established limits.( 2) Safety is not compromised, however, by continuing operation with certain instrumentation channels out of service since provisions were made for this in the plant design.(l)( 3) This Standard outlines limiting conditions for operation necessary to preserve the effectiveness of the reactor control and protection system when any one or more of the channels is out of service.

References:

(1) Final Engineering Report and Safety Analysis, Section 6.

(2) Final Engineering Report and Safety Analysis, Section 6.2.

(3) NIS Safety Review Report, April 1988 Amendment No. 83.17

TABLE 3.5.1-1 REACTOR TRIP SYSTEM INSTRUMENTATION MINIMUM TOTAL NO.

CHANNELS CHANNELS APPLICABLE FUNCTION UNIT OF CHANNELS TO TRIP OPERABLE MODES ACTION I. Manual Reactor Trip 2

I 2

1, 2 I

20 I

2 3* 4* 5*

7

2.

Power Range, Neutron Flux, 4

2 3

1, 2 20 Overpower Trip

3.

Power Range, Neutron Flux, 4

1**

4 1, 2 281 Dropped Rod Rod Stop

4. Intermediate Raige, Neutron 2

I 2

1R9, 2 3

Flux K)

5.

Source Range, Neutron Flux A. Startup 2

Ia

• 2 29*

4 B. Shutdown 2

1**

2 3', 4*, 5*

7 C. Shutdown 2

0 I

3, 4, and 5 5

6.

NIS Coincidentor Logic 2

I 2

1, 2 29 3*, 4*, 5*

7 (D

7.

Pressurizer Variable 3

2 2

199ff 6#

Low Pressure

8. Pressurizer Fixed High 3

2 2

I, 2

69

-+t Pressure 0

9.

Pressurizer High Level 3

2 2

I 6#

10. Reactor Coolant Flow I/loop I/loop in any I/loop in each I

6#

A. Single Loop operating loop operating loop (Above 50% of Full Power)

B.

Two Loops I/Ioop I/loop in two I/loop in each 1####

6#

?

(Below 50% of Full Power) operating loops operating loop II. Steam/Feedwater Flow Mismatch 3

2 2

1, 2 69

12.

Turbine Trip-Low Fluid Oil Pressure 3

2 2

011f 6I

30 TABLE 3.5.1-1 (Continued)

TABLE NOTATION With the reactor trip system breakers in the closed position, the control rod drive system capable of rod withdrawal.

A "TRIP" will stop all rod withdrawal.

The provisions of Specification 3.0.4 are not applicable.

Below the Source Range High Voltage Cutoff Setpoint.

Below the P-7 (At Power Reactor Trip Defeat) Setpoint.

Above the P-7 (At Power Reactor Trip Defeat) Setpoint.

ACTION STATEMENTS ACTION 1 -

With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or be in HOT STANDBY within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

ACTION 2 -

With the number of OPERABLE'channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed provided the following conditions are met:

a. The inoperable channel is placed in the tripped condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.

b. The Minimum Channels OPERABLE requirement is met; however, the inoperable channel may be returned to the untripped condition for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for surveillance testing of other channels per Specification 4.1.

ACTION 3 -

With the number of channels OPERABLE one less than the Minimum Channels OPERABLE requirement and with the THERMAL POWER level:

a. Below the Source Range High Voltage Cutoff Setpoint, restore the inoperable channel -to OPERABLE status prior to increasing THERMAL POWER above the Source Range High Voltage Cutoff Setpoint.

b. Above the Source Range High Voltage Cutoff Setpoint but below.

10 percent of RATED THERMAL POWER, restore the inoperable channel to OPERABLE status prior to increasing THERMAL POWER above 10 percent of RATED THERMAL POWER.

However, one channel may be bypassed for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for surveillance testing per Specification 4.1, provided the other channel is OPERABLE.

ACTION 4 -

With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement suspend all operations involving positive reactivity changes.

Amendment No. 6

)

o30a

-ACTION 5 -

With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, verify compliance with the SHUTDOWN MARGIN requirements of Specification 3.5.2 as applicable, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.

ACTION 6 -

With the number of OPERABLE channels one less than the Total Number of Channels, STARTUP and/or POWER OPERATION may proceed until performance of the next required OPERATIONAL TEST provided the inoperable channel is placed in the tripped condition within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

ACTION 7 -

With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirement, restore the inoperable channel to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or open the reactor trip breakers within the next hour.

ACTION 28 - With the number of OPERABLE channels less than the Minimum Channels OPERABLE requirements, within one hour reduce THERMAL POWER such that Tave is less than or equal to 551.5*F, and place the rod control system in the manual mode.

ACTION 29 - With the number of OPERABLE channels one less than the Minimum Channels OPERABLE requirements, be in at least HOT STANDBY within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />; however, one channel may be removed from service for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> for surveillance testing per Specification 4.1, provided the other channel is OPERABLE.

Amendment No. 8,3117

TABLE 3.5.6-1 ACCIDENT MONITORING INSTRUMENTATION MINIMUM TOTAL NO.

CHANNELS INSTRUMENT OF CHANNELS OPERABLE Pressurizer Hater Level 3

2 Auxiliary Feedwater Flow Indication*

2/steam generator 1/steam generator Reactor Coolant System Subcooling Margin Monitor 2

1 PORV Position Indicator (Limit Switch) 1/valve 1/valve PORV Block Valve Position Indicator (Limit Switch) 1/valve 1/valve Safety Valve Position Indicator (Limit Switch) 1/valve 1/valve 0

Containment Pressure (Hide Range) 2 1

Steam Generator Hater Level (Narrow Range) 1/steam generator 1/steam generator Refueling Hater Storage Tank Level I

1 Containment Sump Hater Level (Narrow Range)**

2 1

C-,

Containment Hater Level (Hide Range) 2 1

Neutron Flux (Hide Range) 2 1

Auxiliary feedwater flow indication for each steam generator to provided by one channel of steam generator level (Hide Range) and one channel of auxiliary feedwater flow rate. These comprise the two channels of auxiliary feedwater flow indication for each steam generator.

Operation may continue up to 30 days with one less than the total number of channels OPERABLE.

39c 3.1,1 CONTINUOUS POWER DISTRIBUTION MONITORING APPLICABILITY: MODE 1 above 90% RATED THERMAL POWER.

OBJECTIVE:

To provide corrective action in the event that the axial offset monitoring system limits are approached.

SPECIFICATION: The incore axial offset limits shall not exceed the functional relationship defined by:

For positive offsets:

IAO.

2.89/P - 2.1225 -

FCC 0.03021 For negative offsets:

IAO = 2.89/P - 2.1181 + FCC

-.03068 where IAO = incore axial offset P = fraction of rated thermal power FCC = The larger of 3.0 or the value in percent of incore axial offset by which the current correlation check differs from the incore-excore correlation.

ACTION:

A.

With-IAO exceeding the limit defined by the specification, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action shall be taken to reduce THERMAL POWER until IAO is within specified limits or such that THERMAL POWER is restricted to less than 90% of RATED THERMAL POWER.

B.

With one or both excore axial offset channel(s) inoperable, as an alternate, one OPERABLE NIS channel for each inoperable excore axial offset channel, shall be logged every two hours to determine IAO.

C.

With no method for determining IAO available, within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> action shall be taken such that THERMAL POWER is reduced to less than 90% of RATED.THERMAL POWER until a method of determining axial offset is restored.

BASIS:

The percent full power axial offset limits are conservatively established considering the core design peaking factor, analytical determination of the relationship between core peaking factors and incore axial offset considering a wide range of maneuvers and core conditions, and actual measurements relating incore axial offset to the axial offset monitoring systems-The axial offset limit established from the incore versus excore data.,have been reduced by an amount equivalent to FCC to allow for burnup and time dependent differences between the periodic correlation verification and the monthly correlation check. Correcting the allowed incore axial offset limits by an amount equal to FCC maintains plant operation within the origianl safety analysis assumption. Should a specific cycle analysis establi.sh that the analytical determination of the relationship between core peaking factors and incore axial offset Amendment No. 77.29

,1J7,117

39d has changed in a manner warranting modification to the existing envelope of peaking factor (1,2), then a change to functional relationship of IAO shall be submitted to the Commission. The incore-excore data correlation is checked or verified periodically as delineated in Specification 3.10.

Reducing power in cases when limits are approached or exceeded, will assure that design limits which were set in consideration of accident analyses are not exceeded. In the event that no method exists for determining IAO, actions are specified to reduce THERMAL POWER to 90% of RATED THERMAL POWER. However, if axial offset channel(s) are inoperable, hand calculational methods of determining IAO from OPERABLE NIS channels can be employed until OPERABILITY of the axial offset channel(s) is restored.

References:

(1) Supporting Information on Periodic Axial Offset Monitoring, San Onofre Nuclear Generating Station, Unit 1, September, 1973 (2) Supporting Information on the Continuous Axial Offset Monitoring System, San Onofre Nuclear Generating Station, Unit 1, July, 1974.

(3) Description and Safety Analysis, Including Fuel Densification, San Onofre Nuclear Gen.erating Station, Unit 1, Cycle 5, January, 1975, Westinghouse Non-Propriety Class 3.

Amendment No. 17.,72117

(

40b 4.1.1.OPERATIONAL SAFETY ITEMS APPLICABILITY:

Applies to surveillance requirements for items directly related to Safety Standards and Limiting Conditions for Operation.

OBJECTIVE:

To specify the minimum frequency and type of surveillance to be applied to plant equipment and conditions.

SPECIFICATION:

A. Reactor Trip System instrumentation shall be checked, tested, and calibrated as indicated in Table 4.1.1.

B. Equipment and sampling tests shall be as specified in Table 4.1.2.

C. The specific activity and boron concentration of the reactor coolant shall be determined to be within the limits by performance of the sampling and analysis program of Table 4.1.2., Item la.

D. The specific activity of the secondary coolant system shall be determined to be within the limit by performance of the sampling and analysis program of Table 4.1.2., Item lb.

E. All control rods shall be determined to be above the rod insertion limits shown in Figure 3.5.2.1 by verifying that each analog detector indicates at least 21 steps above the rod insertion limits, to account for the instrument inaccuracies, at least once per shift during Startup conditions with Keff equal to or greater than one.

F. The position of each rod shall be determined to be within the group demand limit and each rod position indicator shall be determined to be OPERABLE by verifying that the rod position indication system (Analog Detection System) and the step counter indication system (Digital Detection System) agree within $5 steps at least once per shift during Startup and Power Operation except during time intervals when the Rod Position Deviation Monitor is inoperable, then compare the rod position indication system (Analog Detection System) and the step counter indication system (Digital Detection System) at least once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.

G. During MODE 1 or 2 operation each rod not fully inserted in the core shall be determined to be OPERABLE by movement of at least 10 steps in any one direction at least once per 31 days.

H. Instrumentation shall be checked, tested, and calibrated as indicated in Table 4.1.3.

Amendment No. 00,8,117

TABLE 4.1.1 REACTOR TRIP SYSTEM INSTRUMENTATION SURVEILLANCE REQUIREMENTS TRIP ACTUATING DEVICE CHANNEL CHANNEL CHANNEL OPERATIONAL ACTUATION FUNCTIONAL UNIT CHECK CALIBRATION TEST TEST LOGIC TEST

1. Manual Reactor Trip N.A.

N.A.

N.A.

R N.A.

2. Power Range, Neutron Flux S

D (2,3)

M N.A.

N.A.

R (3,4)

3. Power Range, Neutron Flux, N.A.

N.A.

M N.A.

N.A.

Dropped Rod Rod Stop

4. Intermediate Range, S

R (3,4)

S/U (l),M N.A.

N.A.

Neutron Flux

5. Source Range, Neutron Flux S

R (3)

S/U (1),M N.A.

N.A.

6. NIS Coincidentor Logic N.A.

N.A.

N.A.

N.A.

M (5)

7. Pressurizer Variable Low' S

R M

N.A.

N.A.

Pressure

8. Pressurizer Pressure S

R M

N.A.

N.A.

9. Pressurizer Level S

R M

N.A.

N.A.

10. Reactor Coolant Flow S

R Q

N.A.

N.A.

11.

Steam/Feedwater Flow S

R M

N.A.

N.A.

Mismatch

12.

Turbine Trip-Low Fluid N.A.

N.A.

N.A.

S/U (1,6)

N.A.

Oil Pressure

42 TABLE 4.1.1 (Continued)

TABLE NOTATION (1) -

If not performed in previous 31 days.

(2) -

Heat balance only, above 15% of RATED THERMAL POWER. Adjust channel if absolute difference greater than 2 percent.

(3) -

Neutron detectors may be excluded from CHANNEL CALIBRATION.

(4) -

The provisions of Specification 4.0.4 are not applicable for entry into MODE 2 or 1.

(5) -

Each train shall be tested at least every 62 days on a STAGGERED TEST BASIS.

(6) -

Setpoint verification is not applicable.

Amendment No. 7,.117

.430 TABLE 4.1.2 MINIMUM EQUIPMENT CHECK AND SAMPLING FREQUENCY Check Frequency la. Reactor Coolant 1. Gross Activity At least once per 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Samples Determination Required during Modes 1, 2, 3 and 4.

2.

Isotopic Analysis 1 per 14 days. Required for DOSE EQUIVALENT only during Mode 1.

1-131 Concentration

3.

Spectrascopic 1 per 6 months (2) for E (1)

Required only during Determination Mode 1.

4.

Isotopic Analy-a) Once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, (3) sis for Iodine whenever the specific Including 1-131, activity exceeds 1-133, and 1-135.

1.0 u Cl/gram DOSE EQUIVALENT 1-131 or 100/ E (1) u Cl/gram.

b) One sample between 2.and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> following a THERMAL POWER change exceeding 15 percent of the RATED THERMAL POWER within a.one hour period.

5.

Boron concentration Twice/Week (1) E is defined in Section 1.0.

(2) Sample to be taken after a minimum of 2 EFPO and 20 days of POWER OPERATION have elapsed since reactor was last subcritical for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or longer.

(3) Until the specific activity of the reactor coolant system is restored within its limits.

Amendment No. 20,70,0M1l7

(

43e TABLE 4.1.3 MINIMUM FREQUENCIES FOR TESTING. CALIBRATING.

AND/OR CHECKING OF INSTRUMENT CHANNELS Channels Surveillance Minimum Frequency

1. Axial Offset Calibration At each refueling shutdown Check Once per shift

2. Reactor Coolant Calibration At each refueling Temperature shutdown Test Once per month Check Once per shift

3. Pressurizer Calibration At each refueling Pressure shutdown Input to Safety Injection Test Once per month Actuation

4. Rod Position Calibration At each refueling Recorder shutdown Check, comparison with Once per shift during digital readouts operation

5. Charging Flow Calibration At each refueling shutdown

6. Boric Acid Tank Calibration At each refueling Level shutdown Test Once per month

7. Residual Heat Calibration At each refueling Pump Flow shutdown

8. Volume Control Calibration At each refueling Tank Level shutdown.

Test Once per month during MODES I and 2

9. Hydrazine Tank Calibration At each refueling Level shutdown*

Test One per month during operation Amendment No. 117

TABLE 4.1.5-1 ACCIDENT MONITORING INSTRUMENTATION SURVEILLANCE REQUIREMENTS CHANNEL CHANNEL INSTRUMENT CHECK CALIBRATION Pressurizer Hater Level M

R Auxiliary Feedwater Flow Indication*

M R

Reactor Coolant System Subcooling Margin Monitor M

R PORV Position Indicator M

R PORV Block Valve Position Indicator M

R Safety Valve Position Indicator, M

R Containment Pressure (Hide Range)

M R

Steam Generator Hater Level (Narrow Range)

M R

Refueling Hater Storage Tank Hater Level M

R, rD Containment Sump Hater Level (Narrow Range)

M R

Containment Hater Level (Hide Range)

M R

Neutron Flux (Hide Range)

M R**

• See footnote of Table 3.5.6-1.

"*Neutron detectors may be excluded from CHANNEL CALIBRATION.

53a (4) The battery charger for 125 volt DC Bus No. 1 will supply at least 800 amps DC at 130 volts DC for at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, (5) The battery charger for 125 volt DC Bus No. 2 will supply at least 45 amps DC at 130 volts DC for at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and (6) The battery charger for the UPS will supply at least 10 amps AC at 480 volts AC for at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> as measured at the output of the UPS inverter.

d. At least once per 18 months, during shutdown, by verifying that the battery capacity is adequate to supply and maintain in OPERABLE status all of the actual or simulated emergency loads for the design duty cycle when the battery is subjected to a battery service test.

e. At least once per 60 months, during shutdown, by verifying that the battery capacity is at least 80%, 85% for Battery Bank No. 1, of the manufacturer's rating when subjected to a performance discharge test. Once per 60 month interval, this performance discharge test may be performed in lieu of the battery service test required by Surveillance Requirement 4.4.D.2.d.

f. Annual performance discharge tests of battery capacity shall be given to any battery that shows signs of degradation or has reached 85%

of the service life expected for the appli.cation. Degradation is indicated when the battery capacity drops more than 10% of rated capacity from its average on previous performance tests, or is below 90% of the manufacturer's rating.

E. The required Safety Injection-System Load Sequencers shall be demonstrated OPERABLE at least once per 31 days on a staggered test basis, by simulating SISLOP*

conditions and verifying that the resulting interval between each load group is within +/- 10% of its design interval.

F. The required diesel generators and the Safety Injection System Load Sequencers shall be demonstrated OPERABLE at least once per 18 months during shutdown by:

1. Subjecting the diesel to an inspection in accordance with procedures prepared in conjunction with its manufacturer's recommendations for this class of standby service.

Amendment No. 25,50,84,117