ML20062N421

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Proposed TS Tables 3-1 & 3-2 Re Min Frequencies for Checks, Calibrs & Testing of RPS & Min Frequencies for Checks, Calibrs & Testing of ESFs & Instrumentation & Controls, Respectively
ML20062N421
Person / Time
Site: Fort Calhoun Omaha Public Power District icon.png
Issue date: 12/28/1993
From:
OMAHA PUBLIC POWER DISTRICT
To:
Shared Package
ML20062N416 List:
References
NUDOCS 9401130155
Download: ML20062N421 (18)
v • d • e


Text

3!0 SURVEILLANCE REQUIREMENTS 3.1 Instrumentation and Control (continued)

Substantial calibration shifts within a channel (essentially a channel failure) will be revealed during routine checking and testing procedures.

The minimum calibration frequencies of once-per-day for the power range safety channels, and once each refueling shutdown for the process system channels, are considered adequate. l l

The minimum testing frequency for those instrument channels connected to

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Protective System and ' Engineered Safety Features 1s , based , o_n ABB/CE 3robabilistic risk analyses and the ^ accumulation of specific operatincj listory. The quarterly frequency for the channel, functional tests for these systems is based on the analyses presented in the NRC approved topical report CEN-327-A, "RPS/ESFAS Extended Test Interval Evaluation,"

as supplemented, and OPPD's Engineering Analysis EA-FC-93 060 1PS/ESF functional, Test Drift Analysis,"

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safe operat-ion based on District experience in conventiona' plants.

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, t TABLE 3-1 MINIMUM FREQUENCIES FOR CHECKS, CALIBRATIONS AND TESTING OF REACTOR PROTECTIVE SYSTEM Channel Description Surveillance Function Frequency Surveillance Method i I

1. Power Range Safety a. Check 5 a. Comparison of four power channel -l' Channels readings, for botn neutron flux and thermal power. j
b. Adjustment D* b. Channel adjustment to agree with heat balance calculation. j
c. Calibrate S c.

QM Internal test signal to verify -!

trips, alarms, permissives and

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and Test i auctioneer circuits.  ;

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2. Wide-Range Logarithmic a. Check 5 a. Comparison of four wide-range l Neutron Monitors readings. '
b. Test
  • P b. Internal test signals to verify SUR indication and trip, power i level permissives, instrument.

accuracy.

g 3. Reactor Coolant Flow a. Check S a. Comparison of four separate l e total flow indications. -

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, a, g b. Calibrate R b. Known differential pressura ,

I a applied to sensors to calibrate

" all loop devices. ,

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l  ? c. ' Test QM" c. Bistable trip tester.M  !

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TABLE 3-1 (continued)

HININUM FREQUENCIES FOR CHECKS. CALIBRATIONS AND TESTING OF REACTOR PROTECTIVE SYSTEM F TChanneF Description; SurveillAnceT6nction" FFe66'encV ""IsuFveillsiice" MethoF'~~ M "" "'

4. Thermal Margin / Low a. Check: S a. Check: i Pressure 1) Temperature 1) Comparison of four separate Input calculated trip pressure set i point indications.
2) Pressure 2) Comparison of four Input pressurizer pressure ,

indications (same as 5(a)  !

l below). .

w b. Calibrate: R b. Calibrate:

1 1) Temperature 1) Known resistance substituted Input for RTD coincident with known pressure input.

2) Pressure 2) Known pressure applied to ,

Input sensor coincident with above temperature calibrations.

c. Test (54* c. Bistable trip tester.")
5. High-Pressurizer a. Check S a. Comparison of four separate Pressure pressure indications.

l b. Calibrate R b. Known pressure applied to sensors.

c. A Bistable trip tester.08 l Test $4 c.

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TABLE 3-1 (continued) i MINIMUM FREQUENCIES FOR CHECKS, CAiIBRATIONS AND TESTING OF REACTOR PROTECTIVE SYSTEM LCh'annel20escridfion Surieillance Functioni 1

Frequency ' Surveillance Method' 3

6. Steam Generator Level a. Check S a. Comparison of four level indications per generator.
b. Calibrate R b. Known differential pressure applied to sensors.
c. Test Q4* c. Bistable trip tester.M
7. Steam Generator Pressure a. Check S a. Comparison of four pressure indications per generator.
b. Calibrate R b. Known pressure applied to sensors.
c. Test QM" c. Bistable trip tester.M
8. Containment Pressure a. Calibrate R a. Known pressure applied to sensors.
b. Test Q:4" b. Simulate pressure switch action. ,
9. Loss of Load a. Test P a. Manually trip 2/4 turbine main steam stop valves.

g 10. Manual Trips a. Test P a. Manually test both circuits.

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g 11. Steam Generator a. Check 5 a. Comparison of four differential e Differential Pressure pressure indications between the two 5 steam generators.

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b. Calibrate R b. Known differential pressure applied to sensors. ,
c. Test QM" c. Bistable trip test.M

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4 TABLE 3-1 (continued)

HINIMUM FREQUENCIES FOR CHECKS, CALIBRATIONS AND TESTING OF REACTOR PROTECTIVE SYSTEM

"" ich'annel'Descriptici Su ssi11ance Funktion Friquenc9 " SuWeillance Meth6dB "i""~'" '? "Y '

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12. _ Reactor Protection a. Test QM a. Internal test circuits check logic System Logic Units networks and clutch power contactors.
13. - Axial Power a. Check 5 a. 1. Comparison of four separate Distribution axial index indications.
2. Comparison of four separate upper trip set point indications.

v 3. Comparison of four separate 4 lower trip set point indications.

b. Calibrate R b. Known currents applied to input of axial shape index calculator.
c. Test QM9 c. Trip test known axial shape index applied to input of axial shape;index

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, . NOTES: (1) The bistable trip tester injects a signal into the bistable and provides a precision readout 6 of the trip set point.

42 (2) ^mentFlyThh]hGjj(ef)jtestswillbedoneononlyoneoffourchannelsatatimetoprevent 22 reactor trip.

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m (3) Calibrate using built-in simulated signals.

!" (4) Not required unless the reactor is in the power operating condition and is therefore not required during plant startup and shutdown periods.

TABLE 3-2 MINIMUM FREQUENCIES FOR CHECK 3, CALIBRATIONS AND TESTING OF ENGINEERED SAFETY FEATURES, INSTRUMENTATION AND CONTROLS Channel Description Surveillance Function Frec.uency Surveillance Method _

I. Pressurizer Pressure a. Check S a. Comparison of four separate pressure Low indications.

b. Calibrate R b. Known pressure applied to sensors and PPLS actuation and blocking logic verified.
c. Test QPYR M
c. Signal to meter relay adjusted with test device to trip one channel at a time.
2. Pressurizer Low a. Calibrate R a. Part of 1(b) above.

w Pressure Blocking 4 Circuit

3. Safety injection a. Test Q4 a. Simulation of PPLS or C4P6 CPfi$ 2/4 Actuation logicusingbuilt-intestinfsystem.

Both " standby power" and "no standby power" circuits will be tested for A and B channels. Test will verify functioning of initiation circuits of dll equipment normally operated by safety feature actuation signals.

$ b. Test R b. Complete automatic test initiated sensor

@ operation (Item 1(b) or 4(b)) and g including all normal operation.

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" 4. Containment Pressure a. Calibrate R a. Known pressure applied to sensors and High Signal CPHS actuation logic verified.

u, b. Test QM b. Pressure switch operation simulated one

? circuit at a time.

TABLE 3-2 (continued)

HINIMUM FREQUENCIES FOR CHECKS, CALIBRATIONS AND TESTING OF ENGINEERED SAFETY FEATURES, INSTRUMENTATION AND CONTROLS Channel Description Surveillance Function Frequency Surveillance Nethod

5. Containment Spray a. Test QM a. Simulation of PPLS and CPHS 2/4 logic using built-in testing system. Both " standby

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Logic power" and "no standby power" circuits will be tested for A and B channels. Test will verify functioning of initiation circuits of all equipment normally operated by safety feature actuation signals.

b. Test R b. Complete automatic test initiated sensor operation (Item 1(b) and 4(b)) and including all normal automatic operations.

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, 6. Containment Radiation a. Check D a. Normal readings observed and internal test High Signal ** signals used to verify instrument operation.

b. Test QM
b. Detector exposed to remote operated radiation check source or test signal to verify instrumentation, one. channel at a time, and isolation lockout relay functional check.
c. Calibrate R c. Secondary and Electronic Calibration g performed at refueling frequency. Primary o calibration performed with exposure to E radioactive sources only when required by g the secondary and electronic calibration.

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TABLE 3-2 (continued)

HINIMUM FREQUENCIES FOR CHECKS, CALIBRATIONS AND TESTING OF ENGINEERED SAFETY FEATURES, INSTRUMENTATION AND CONTROLS Channel Description Surveillance Function Frequenc_y Surveillance Method

7. Manual Safety Injection a. Test R a. Manual initiation.

Initiation

8. Manual Containment a. Test R a. Manual initiation.

Isolation Initiation

b. Check R b. Observe isolation valves closure.

Y 9. Manual Initiation a. Test R a. Manual switch operation; pumps and valves Containment Spray tested separately.

10. Automatic Load a. Test Q a. Proper operation will be verified during Sequencers safety feature actuation test of Item 3(a) above.

f 11. Diesel Testing See Technical Specification 3.7 a

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TABLE 3-2 (continued)

HINIMUM FREQUENCIES FOR CHECKS. CALIBRATIONS AND TESTING OF ENGINEERED SAFETY FEATURES, INSTRUMENTATION AND CONTROLS Channel Description Surveillance Function Frequency Surveillance Method

12. Diesel Fuel Transfer a. Test M a. Pump run to refill day tank.

Pump

13. SIRW Tank Low Level a. Check S a. Verify level indication between independent Signal channels.
b. Test QM

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b. A test pressure simulating the tank level' is applied to each tank bubbler, one at a time.

l ll c. Calibrat4sn e R c. Known level signal applied to sensors and STLS logic verified.

14. Safety Injection a. Check 5 a. Verify that level and pressure indications Tank Level and are between independent high and low alarms Pressure Instruments for level and pressure.
b. Calibrate R b. Known pressure and differential pressure y applied to pressure and level sensors.

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TABLE 3-2 (continued)

HINIMUM FREQUENCIES FOR CHECKS, CALIBRATIONS AND TESTING OF ENGINEERED SAFETY FEATURES, INSTRUMENTATION AND CONTROLS .

Channel Description Surveillance Function Frequency Surveillance Method L

15. Boric Acid Tank Level a. Check D a. Compare two independent sensors.
b. Test R b. Pump tank below low-level alarm point to verify switch operation.
c. Calibrate R c. Known differential pressure applied to level sensors. At least three points in indicator range will be obtained-high, middle-of-range, and low (near alarm set-i point). ,

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16. Boric Acid Tank a. Check D a. Observe temperature devices for proper Temperature Indication readings. '
17. Steam Generator Low a. Check S a. Compare four independent pressure Pressure Signal (SGLS) indications. i
b. Test Q"M" b. Simulated signal.

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gj' c. Calibrate R c. Known pressure applied to sensors to oa verify trip points, logic operation, ,

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TABLE 3-2 (continued)

MINIMUM FREQUENCIES FOR CHECKS, CALIBRATIONS AND TESTING OF ,

ENGINEERED SAFETY FEATURES. INSTRUMENTATION AND CONTROLS .

l Channel Description Surveillance Function Frequency Surveillance Method .

i l

18. SIRW Tank Temperature a. Check D a. Compare two independent temperature Indication & Alarms readings.
b. Test QM b. Measure temperature of SIRW tank with
standard laboratory instruments.

! 19. Recirculation Actuation a. Test R a. Manual initiation.

4 Switches w

d. 20. Recirculation Actuation a. Test QM a. Part of test 3(a) using built-in testing systems to initiate STLS.

~

M Logic i b. Test R~ b.. Complete automatic test initiated -

sensor operation.

21. 4.16 KV Emergency Bus a. Check 5 a. Verify voltage readings are above alarm Low Voltage (Loss of initiation on degraded voltage level -

$ Voltage And Degraded supervisory lights "on".

@ Voltage)

- c. b. Test QM b. Undervoltage relay operation simulated one circuit at a time.

_, c. Calibrate R c. Known voltage applied to sensors and circuit breaker trip actuation logic verified. ,

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$ - "cten: (1) "ct required urless pressurizer prc ure is above 1700 pria.

(2) "Ot required unic:: Stear ger.cratcr prc ure i: abcvc 500 pria. 1 1

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TABLE 3-2 (continued)

MINIMUN FREQUENCIES FOR CHECKS, CALIBRATIONS AND TESTING OF ENGINEERED SAFETY FEATURES, INSTRUMENTATION AND CONTROLS Channel Description Surveillance Function Frecuency Surveillance Method

22. Auxiliary Feedwater .
a. Steam Generator Water a. Check S a. Compare independent level readings.

Level Low (Wide Range)

b. Calibrat4sn e R b. Known signal applied to sensor.
b. Steam Generator a. Check S a. Compare independent pressure Pressure Low readings.
b. Calibrat4en e R b. Known signal applied to sensor, ,

w i a. Calibrate >

[ c. Steam Generator R a. Known signal applied to sensor.

m Differential Pressure  :

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d. Actuation Circuitry QM

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b. Test g R b. System functional test of AFW  ;

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U.S. Nuclear Regulatory Conynission LIC-93-0299 NTTACHMENT B

9 DISCUSSION JUSTIFICATION AND NO SIGNIFICANT HAZARDS CONSIDERATIONS DISCUSSION AND JUSTIFICATION: i Omaha Public Power District (OPPD) proposes to amend the Fort Calhoun Station (FCS) Unit No. 1 Technical Specifications (TS) to revise the TS surveillance test frequency from '

to quarterly for several channel functional tests for the Reactor Protective monthly System (RPS) and Engineered Safety Features (ESF) Instrumentation and Controls based:

upon NRC approval of CEN-327-A and its associated supplement (Supplement 1). Increasing the surveillance test interval (STI) minimizes the potential for inadvertent ESF '

actuations and reactor trips during surveillance testing.

The proposed change revises several selected instrumentation channel functional test frequencies currently found in TS 3.1, Table 3-1 " Minimum Frequencias for Checks, Calibrations and Testing of Reactor Protective System" and Table 3-2 " Minimum Frequencies for Checks, Calibrations and Testing of Engineered Safety Features, Instrumentation and Controls." However, the STI for the RPS and ESF Instrumentation and Controls Channel Calibrations will remain as currently required (i.e., refueling frequency).

In addition, the TS 3.1 " Instrumentation and Control" Basis Section is being revised to support the changed instrumentation channel functional test frequency.

1 In Generic Letter 83-28 " Required Actions Based on Generic Implications of Salem ATWS l Events", the NRC required plants to review the Reactor Trip System (RTS) test intervals to determine if they were consistent with achieving high RTS availability. Combustion Engineering (CE) performed an analysis to evaluate the availability of the RTS given the 30-day test interval required by the TS. Sensitivity analysis performed as part of this evaluation indicated that the unavailability of the RTS was relatively insensitive to I change in the failure rates of certain components. Later, as a follow up to the original sensitivity analysis, the impact of extending the STI for selected components in the RPS and Engineered Safety Features Actuation System (ESFAS) was evaluated by CE.

This analysis is documented in CEN-327-A "RPS/ESFAS Extended Test Interval Evaluation."

In CEN-327-A, four RPS fault tree models developed previously for the Combustion Engineering Owner's Group (CE0G) were expanded to cover ' all RPS electro 1ic trip parameters. The new models, which included the FCS RPS design, were then used to determine the RPS reliability for both monthly and quarterly test intervals. The model took into account: common mode failures, operator errors, reduced redundancy, and random component failures. The study results show that for the FCS RPS, the decrease incoremelpfrequencyattributabletothereducedexposuretotest-inducedtransients  :

is 2.63x10' per year for a 90-day test interval for all parameters. The increase in '

core me}t frequency due to the increase in system unavailability is no more than 2.22x10~ per year for all parame This results in a net decrease in core melt frequency of approximately 4.1x10'gers. per year.

1 Fault tree models were also constructed for each of the ESFAS signals for the different  ;

plant classes used for the RPS analysis. Each ESFAS f ault tree model specifically I addressed common mode f ailures, operator error, reduced redundancy, and random component failures. The study found that for FCS, the decrease i reduced exposure to test-induced transients is 8.78x10'gper core melt year frequency while due to ithe the increase coremeltfrequencyduetotheincreaseinsystemunavailabilityislessthan5.3x10g per year. Therefore, for the FCS RPS and ESFAS, the net impact of extending the test interval to 90 days is a slight decrease in the core melt frequency.

a CEN-327-A, which was submitted to the NRC for review in June, 1986, recommended more restrictive test intervals (30-day test interval to 60-day for certain RPS trip parameters and 30-day to 90-day for ESFAS actuation logic). In March, 1989, CE issued CEN-327-A, Supplement 1, which presented changes in RPS reliability that resulted from extending the test intervals from 30 days to 90 days for all RPS trip parameters and recommended a 90-day test interval with sequential testing. CEN-327-A,-Supplement 1, re-evaluated nineteen RPS trip parameters which in CEN-327-A had resulted in a slight increase in overall core melt frequency. The results of the re-analysis demonstrated that the STIs could be increased to 90 days with no significant increase in RPS

  • unavailability.

The analysis results presented in CEN-327-A and CEN-327-A. Supplement 1, demonstrate that the STI for RPS and ESFAS components can be increased without increasing public risk. In fact, for the 90-day test interval, the overall impact is a slight decrease in core melt frequency. Extending the STI does not change the trip per test frequency, but does reduce the trip per year frequency.

In November, 1989, the NRC issued a Safety Evaluation Report (SER) for CEN-327-A and ',

CEN-327-A, Supplement 1. The NRC stated that it was acceptable to extend the STIs for the RPS and ESFAS from 30 days to 90 days for all CE plants (excluding Maine Yankee).

This approval was contingent upon each plant confirming that instrument drift occurring over the proposed STI would not cause the setpoint values to exceed those assumed in the safety analysis and specified in the fS. The NRC SER stated that: licensees must confirm that they have reviewed instrument drifc information for each channel involved and have determined that drift occurring in that channel over the period of extended STIs would not cause the setpoint value to exceed the allowable value as calculated for that channel by the licensee's methodology; each licensee should have onsite records of the as-found and as-left values showing actual calculations and supporting data for planned future NRC audits; the records should consist of monthly data over a period of the last two to three years with the current plant-specific setpoint methodology used to derive the safety margins.

A plant specific calculation /setpoint drift analysis was conducted, as required by the NRC SER, that analyzed the effect on instrument drif t of extending the RPS and ESF Instrumentation and Controls functional STI from monthly to quarterly. A 4-month drif t interval was calculated to bound the quarterly interval plus the 25% maximum allowable extension period permitted in the FCS Technical Specifications. It was determined, via review of all affected RPS and ESF instrumentation channels, that the only components requiring further analysis as to potential impact on setpoint drift were the RPS bistables and variable setpoint circuitry. Therefore, three years (1990-1993) of as-found and as-lef t RPS functional surveillance test data was reviewed for potential impact on setpoint drif t with a quarterly STI. The results demonstrated that the

observed changes in instrument uncertainties for the extended STI do not exceed the current 30-day setpoint assumptions. It is, therefore, unnecessary to change any setpoints to accommodate the proposed extended STI.

The proposed changes to TS Tables 3-1 and 3-2 implement the guidance provided in Generic Letter 93-05 "Line-Item Technical Specifications Improvements to Reduce Surveillance Requirements for Testing During Power Operation." Specifically, Line-Item 5.1 " Nuclear Instrumentation Surveillance" is implemented as the RPS/ESFAS functional test frequencies of those items listed in TS Tables 3-1 and 3-2 are being revised from monthly to quarterly, a

'[ .

Please' note that the 4.160 kV Emergency. Bus Low Voltage (Table 3-2, Item No. 21)ftest frequency is being revised from monthly to quarterly. The CE Standard TS (NUREG 1432) allows a refueling test interval, however, the CE analysis (CEN-327-A) only justifies

~

a quarterly test frequency for Fort Calhoun Station. The additional RPS/ESFAS functional test frequencies reflect the CE STS (NUREG 1432) surveillance frequency of 92 days which is based on NRC approval of topical report CEN-327-A. H 1

Administrative Changes j

'In order to enhance. readability and retain consistency in TS Tables 3-1 and 3-2, 0 PPD- -i is revising the format of the applicable pages including positioning of the page numbers, inserting column headings, repositioning the footnotes, ' correcting i typographical errors, revising " Calibration" to " Calibrate" to~ provide consistency, and I performing other structural formatting of the tables. These revisions are strictly I administrative in nature.

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NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION:

The proposed change does not involve si hazards considerations because operation of Fort Calhoun Station Unit (FCS)gnificant No.1 in accordance with this change would not:

(1) Involve a significant increase in the probability or consequences of an accident previously evaluated.

Increasing the surveillance test interval (STI) from monthly to quarterly for the Reactor Protective System (RPS) and Engineered Safety Features Actuation System (ESFAS) instrumentation has two principal effects with opposing impacts on core melt risk. The first impact is a slight increase in core melt frequency that results from the increased unavaildF11ity of the instrumentation in questlon.

The unavailability of t1e tested inwumentation components is translated to result in a failure of the reactoe to trip, an Anticipated Transient Without Scram (ATWS), or a failure of the appropriate engineered safety features to actuate when required. The opposing impact on core melt risk is the corresponding reduction in core melt frequency that would result due to the reduced exposure of the plaat to test-induced transients.8 This results in a net decrease in core melt frequency of approximately 4.1x10- per year.

Representative fault tree models were developed for FCS and the corresponding changes in core melt frequency were quantified in evaluations CEN-327-A and CEN-327-A, Supplement 1. The NRC issued a Safety Evaluation Report (SER) which found that these evaluations were acceptable for justifying the extensions in the STIs for the RPS and ESFAS from 30 days to 90 days and that the RPS unavailabilities resulting from extending the STIs were not considered to be significant.

Estimates of the reduction in scram frequency from the reduction in test-induced scrams and the corresponding reduction in core melt frequency were found acceptable. STIs of 90 days were found to result in a net reduction in core melt risk.

A plant specific calculation /setpoint drift analysis was conducted, as required by the NRC SER, that analyzed the effect on instrument drift of extending the RPS-and ESF instrumentation and controls functional STI from monthly to quarterly.

The results demonstrated that the observed changes in instrument uncertainties for the extended STI do not exceed the current 30-day setpoint assumptions.

Therefore, it is unnecessary to change any setpoints to accommodate the proposed extended STI.

Operation of the facility in accordance with this proposed change, therefore, will not involve a significant increase in the probability or consequences of an accident previously evaluated.

(2) Create the possibility of a new or different kind of accident from any accident previously evaluated.

The proposed change does not involve any changes in equipment and will not alter the manner in which the plant will be operated. RPS and ESFAS setpoints will not '

be changed as the instrument uncertainties resulting from the proposed STI (calculatedusingactualplantdata)arelessthantheinstrumentuncertainties assumed f or 30 days. Thus, this proposed change will not create the possibility of a new or different kind of accident from any previously evaluated.

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i (3) ,

Involve a significant reduction in a margin of safety.

There are- no changes to the equipment or plant operations. RPS and ESFAS setpoints will not be changed as the instrument uncertainties resulting from the proposed STI (calculated using actual plant data) are less than the instrument, uncertainties assumed for 30 days.

Implementation of the proposed changes is expected to result in an overall improvement in plant safety due to the fact that reduced testing intervals will result in fewer inadvertent reactor trips and less frequent actuation of ESFAS - -

components. The conclusions of the accident analyses in the FCS Updated Safety l Analysis Report (USAR) remain valid and the safety limits continue to be met. '

Thus, this proposed change does not reduce a margin of safety.

1 Therefore, based on the previous considerations, it is OPPD's position that this proposed amendment does not involve significant hazards considerations as defined by 10 CFR 50.92 and the proposed changes will not result in a condition which significantly alters the impact of FCS on the environment. The frequencict of testing RPS and ESFAS instrumentation involve no change in the amount or type of any effluent that may be.

released offsite and there is no increase in individual or cumulative occupational radiation exposure. Thus, the proposed changes meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9) and pursuant to 10 CFR 51.22(b), '

no environmental assessment need be prepared. '

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