ML100550639

Developmental Revision B - Technical Requirements Manual Bases B 3.3- Instrumentation

ML100550639
Person / Time
Site:	Watts Bar
Issue date:	02/02/2010
From:	Tennessee Valley Authority
To:	Office of Nuclear Reactor Regulation
References
Download: ML100550639 (29)

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RTS Instrumentation B 3.3.1 B 3.3 INSTRUMENTATION B 3.3.1 Reactor Trip System (RTS) Instrumentation BASES BACKGROUND A reactor trip signal acts to open two trip breakers connected in series, feeding power to the control rod drive mechanisms. The loss of power to the mechanism coils causes the mechanisms to release the rod cluster control assemblies which then fall by gravity into the core. There are various instrumentation delays associated with each trip function, including delays in signal actuation, in opening the trip breakers, and in the release of the rods by the mechanisms. The total delay to trip is defined as the time delay from the time that trip conditions are reached to the time the rods are free and begin to fall (Ref. 1). Furthermore, RTS RESPONSE TIME is defined as the time required for the reactor trip (i.e., the time the rods are free and begin to fall) to be initiated following a step change in the variable being monitored from at least five percent below (or above) to at least five percent above (or below) the trip setpoint (Ref. 2). This definition has been clarified in the Technical Specifications.

Limiting trip setpoints assumed for each trip function are given in Reference 1.

The difference between the limiting trip setpoint assumed for the analysis and the nominal trip point represents an allowance for instrumentation channel error and setpoint error. During plant startup tests, it is demonstrated that actual instrument time delays are equal to or less than the assumed values. Additionally, protection system channels are calibrated and instrument response times determined periodically in accordance with the plant Technical Specifications and this Technical Requirement.

APPLICABLE The RTS functions to maintain the SLs during all Anticipated Operational SAFETY Occurrences (AOOs) and mitigates the consequences of DBAs in all ANALYSES MODES in which the Reactor Trip Breakers are closed.

Each of the analyzed accidents and transients can be detected by one or more RTS functions. The accident analyses described in Reference 3 take credit for most RTS trip functions. RTS trip functions not specifically credited in the accident analyses have an N/A (Not Applicable) response time requirement in Table 3.3.1-1. They are qualitatively credited in the safety analyses and the NRC staff-approved licensing basis for the plant.

(continued)

Watts Bar - Unit 2 B 3.3-1 Technical Requirements (developmental) A

RTS Instrumentation B 3.3.1 BASES (continued)

APPLICABLE These RTS trip functions may provide protection for conditions which do SAFETY not require dynamic transient analysis to demonstrate function ANALYSES performance. These RTS trip functions may also serve as backups to (continued) RTS trip functions that were credited in the accident analysis.

The safety analyses applicable to each RTS function are discussed in the bases for the Technical Specifications, B.3.3.1 (Ref. 4).

TR OPERABILITY requirements for the RTS Instrumentation and interlocks are specified in Technical Specifications, section 3.3.1. TR 3.3.1 requires the RTS Instrumentation and interlocks of Table 3.3.1-1 of the TR to be OPERABLE with RESPONSE TIMES as shown in the table. RESPONSE TIMES must be within the specified limits for the affected instruments to be considered OPERABLE.

APPLICABILITY Applicable MODES for the specific RTS Instrumentation and interlocks are delineated in Table 3.3.1-1 of Reference 4. The bases for Applicability of each function is included in Reference 4.

ACTIONS A.1 The Required Actions for inoperable instruments are found in Reference 4. With one or more RESPONSE TIMES outside the specified limits, the affected instrument(s) must be considered inoperable and the appropriate Action referenced in Table 3.3.1-1 of Reference 4 must be taken. The bases for these actions is found in Reference 4.

(continued)

Watts Bar - Unit 2 B 3.3-2 Technical Requirements (developmental) A

RTS Instrumentation B 3.3.1 BASES (continued)

TECHNICAL TSR 3.3.1.1 SURVEILLANCE REQUIREMENTS TSR 3.3.1.1 demonstrates that the RTS RESPONSE TIME of each reactor trip function is within the limits listed in Table 3.3.1-1 of the TR.

This ensures that the time delays assumed in the safety analyses are not exceeded. Each train's response must be verified every 18 months on a STAGGERED TEST BASIS (e.g., Train A at 18 months after initial startup, Train B at 36 months, and then Train A again). Response times cannot be determined during plant operation because equipment operation is required to measure response times. Experience has shown that these components usually pass this surveillance when performed on the 18-month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

Table 3.3.1-1 of this TR specifies the RESPONSE TIMES for the RTS.

REFERENCES 1. Watts Bar FSAR, Section 15.1.3. "Trip Points and Time Delays To Trip Assumed in Accident Analyses."

2. Watts Bar FSAR, Section 7.0 "Instrumentation and Controls."

3. Watts Bar FSAR, Section 15.0 "Accident Analyses."

4. Watts Bar Technical Specifications (Unit 2), Section 3.3.1, "Reactor Trip Instrumentation, and Bases for 3.3.1.

Watts Bar - Unit 2 B 3.3-3 Technical Requirements (developmental) A

ESFAS Instrumentation B 3.3.2 B 3.3 INSTRUMENTATION B 3.3.2 Engineered Safety Features Actuation System (ESFAS) Instrumentation BASES BACKGROUND The ESFAS initiates necessary safety systems, based upon the values of selected unit parameters, to protect against violating core design limits and the Reactor Coolant System (RCS) pressure boundary, and to mitigate accidents. A detailed Background for ESFAS is given in Reference 1. This TR covers only RESPONSE TIME testing.

The ESFAS RESPONSE TIME is defined as the interval required for the ESF sequence to be initiated subsequent to the time that the appropriate variables exceed the setpoints. This definition is augmented in the Standard Technical Specifications to include automatic system lineups and diesel generator starting and sequence loading delays. The ESF sequence is initiated by the output of the ESFAS, which is by the operation of the dry contacts of the slave relays (600 series relays) in the output cabinets of the Solid State Protection System (SSPS). The RESPONSE TIMES listed in Table 3.3.2-1 of this TR include the interval of time which will elapse between the time the parameter as sensed by the sensor exceeds the safety setpoint and the time the SSPS slave relay dry contacts are operated. The values listed are maximum allowable values consistent with the safety analyses and this Technical Requirement and are systematically verified during plant preoperational startup tests. For channels that include dynamic transfer functions (e.g., lag, lead/lag, rate/lag, etc.), the response time test may be performed with the transfer functions set to one with the resulting measured response time compared to the appropriate FSAR response time. Alternately, the response time test can be performed with the time constants set to their nominal value provided the required response time is analytically calculated assuming the time constants are set at their nominal values. The response time may be measured by a series of sequential tests such that the entire response time is measured. The overall ESFAS RESPONSE TIMES are listed in this TR.

The ESFAS is always capable of having response time tests performed using the same methods as those tests performed during the preoperational test program or following significant component changes (Ref. 2).

(continued)

Watts Bar - Unit 2 B 3.3-4 Technical Requirements (developmental) A

ESFAS Instrumentation B 3.3.2 BASES (continued)

APPLICABLE The required channels of ESFAS Instrumentation provide plant protection SAFETY in the event of any of the analyzed accidents. The accident analyses ANALYSES described in Reference 3 take credit for operation of ESF systems during DBAs. The safety analyses applicable to each ESFAS function are discussed in the bases for the Technical Specifications, B 3.3.2 (Ref. 1),

B 3.3.5 (Ref. 4) and B 3.3.6 (Ref. 5).

TR OPERABILITY requirements for ESFAS Instrumentation are specified in Technical Specifications, LCOs 3.3.2, 3.3.5 and 3.3.6. TR 3.3.2 requires the ESFAS Instrumentation of Table 3.3.2-1 of the TR to be OPERABLE with RESPONSE TIMES as shown in the table. RESPONSE TIMES must be within the specified limits for the affected instruments to be considered OPERABLE.

APPLICABILITY Applicable MODES for the specific ESFAS Instrumentation are delineated in Table 3.3.2-1 of Reference 1; in the Applicability of Reference 4; and in Table 3.3.6-1 of Reference 5. The bases for Applicability of each function is included in References 1, 4 and 5.

ACTIONS A.1 The required Actions for inoperable instruments are found in Reference 1.

With one or more RESPONSE TIMES outside the specified limits, the affected instrument(s) must be considered inoperable and the appropriate Action referenced in Table 3.3.2-1 of Reference 1; the Actions of Reference 4; or the appropriate Action of Table 3.3.6-1, must be taken.

The bases for these actions is found in References 1, 4 and 5.

(continued)

Watts Bar - Unit 2 B 3.3-5 Technical Requirements (developmental) A

ESFAS Instrumentation B 3.3.2 BASES (continued)

TECHNICAL TSR 3.3.2.1 SURVEILLANCE REQUIREMENTS TSR 3.3.2.1 demonstrates that the ESFAS RESPONSE TIME of each ESFAS function is within the limits listed in Table 3.3.2-1 of the TR. This ensures that the time delays assumed in the safety analyses are not exceeded. Response time tests are conducted on an 18 month STAGGERED TEST BASIS. The 18 month Frequency was developed considering it was prudent that these Surveillances only be performed during a plant outage. This was due to the plant conditions needed to perform the Surveillance and the potential for unplanned plant transients if the Surveillance is performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed on the 18 month Frequency.

Table 3.3.2-1 of this TR specifies the RESPONSE TIMES for the ESFAS Instrumentation.

REFERENCES 1. Watts Bar Technical Specifications (Unit 2), Section 3.3.2, "Engineered Safety Features Actuation System Instrumentation, and Bases for 3.3.2.

2. Watts Bar FSAR, Section 7.3.1.2.6, "Minimum Performance Requirements."

3. Watts Bar FSAR, Section 15.0 "Accident Analyses."

4. Watts Bar Technical Specifications (Unit 2), Section 3.3.5, "LOP Diesel Generator Start Instrumentation," and Bases for 3.3.5.

5. Watts Bar Technical Specifications (Unit 2), Section 3.3.6, "Containment Vent Isolation Instrumentation," and Bases for 3.3.6.

Watts Bar - Unit 2 B 3.3-6 Technical Requirements (developmental) A

Power Distribution Monitoring System (PDMS)

B 3.3.3 B 3.3 INSTRUMENTATION B 3.3.3 Power Distribution Monitoring System (PDMS)

BASES BACKGROUND The Power Distribution Monitoring System (PDMS) generates a continuous measurement of the incore power distribution using the methodology documented in Reference 1. The PDMS employs an advanced three-dimensional nodal code to calculate the incore power distribution. The reference incore power distribution is continuously normalized to the incore flux measurements from the self-powered detector elements. On a nominal once-per-minute basis, the incore power distribution is updated with self powered detector measurements and other plant instrumentation.

The PDMS incore power distribution measurement can be used to determine the most limiting core peaking factors, FNH, the Nuclear Enthalpy Rise Hot Channel Factor (Technical Specification 3.2.2) and FQ(Z), the Heat Flux Hot Channel Factor (Technical Specification 3.2.1).

The incore power distribution measurement can also be used in the calibration of the excore neutron flux detection system (Technical Specification 3.3.1), monitoring the QUADRANT POWER TILT RATIO (QPTR) (Technical Specification 3.2.4), and verifying the position of a rod with inoperable position indicators (Technical Specification 3.18).

The PDMS requires information on current plant and core conditions in order to determine the core power distribution using the core peaking factor measurement and measurement uncertainty methodology described in Reference 1. The OPERABILITY of the PDMS with the specified minimum complement of instrumentation channel inputs ensures that the measurements obtained from use of this system accurately represent the spatial neutron flux distribution of the core. The PDMS requires input for average reactor vessel inlet temperature, reactor power level, control bank positions, and signals from the Self-Powered Detector (SPD) elements.

The OPERABLE PDMS is to be used for calibration of the Excore Neutron Flux Detection System, monitoring the QUADRANT POWER TILT RATIO, or measurement of FQ(Z) or FNH. Similarly, the PDMS may be used for verifying the position of a rod with inoperable position indicators.

(continued)

Watts Bar - Unit 2 B 3.3-7 Technical Requirements (developmental) B

Power Distribution Monitoring System (PDMS)

B 3.3.3 BASES APPLICABLE The PDMS is used for periodic measurement of the core power SAFETY distribution to confirm operation within design limits and periodic ANALYSES calibration of the excore detectors. This system does not initiate any automatic protection action. The PDMS is not assumed to be OPERABLE to mitigate the consequences of a DBA or transient (References 2 and 3).

TR TR 3.3.3 requires the PDMS to be OPERABLE with the specified number of instrument channel inputs from the plant computer for each function listed in Table 3.3.3-1. The PDMS is OPERABLE when the required channel inputs are available, the calibration data set is valid, and reactor power is > 25% RTP.

This TR ensures the OPERABILITY of the PDMS when required to monitor the power distribution within the core. The PDMS is used for periodic surveillance of the incore power distribution and calibration of the excore detectors. The surveillance of incore power distribution verifies that the peaking factors are within their design envelope (Reference 3).

The peaking factor limits include measurement uncertainty which bounds the actual measurement uncertainty of an OPERABLE PDMS (Reference 1).

Maintaining the minimum number of instrumentation channel inputs ensures the uncertainty is bounded by the uncertainty methodology.

Similarly, when THERMAL POWER is less than 25% RTP, then the accuracy of the adjustment provided by the Core Exit Thermo-Couples (CETCs) to the measured PDMS power distribution may not be bounded by the uncertainties documented in Reference 1.

APPLICABILITY The PDMS must be OPERABLE when it is used for calibration of the Excore Neutron Flux Detection System, monitoring the QPTR, measurement of FNH and FQ(Z), or verifying the position of a rod with inoperable position indicators.

(continued)

Watts Bar - Unit 2 B 3.3-8 Technical Requirements (developmental) B

Power Distribution Monitoring System (PDMS)

B 3.3.3 BASES (continued)

ACTIONS A.1 The Required Action A.1 has been modified by a Note stating that the provisions of TR 3.0.3 do not apply.

With THERMAL Power less than 25% RTP or with one or more required channel inputs inoperable or unavailable to the PDMS, the PDMS must not be used to obtain an incore power distribution measurement.

Therefore, the Required Action A.1 prohibits the use of the inoperable system for the applicable monitoring or calibration functions.

TECHNICAL TSR 3.3.3.1 SURVEILLANCE REQUIREMENTS Performance of the CHANNEL CHECK ensures that a gross instrumentation failure has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels.

A CHANNEL CHECK will detect gross channel failure, thus it is a key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION. Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including isolation, indication, and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit. If the channels are within the criteria, it is an indication that the channels are OPERABLE.

The Frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is sufficient considering the PDMS provides automatic validation of the channel inputs and either discards the inoperable channel input or declares itself inoperable, but at the same time ensures that the required channel inputs to the PDMS are manually verified to be valid within a reasonable time frame prior to using the PDMS to obtain an incore power distribution measurement.

(continued)

Watts Bar - Unit 2 B 3.3-9 Technical Requirements (developmental) B

Power Distribution Monitoring System (PDMS)

B 3.3.3 BASES (continued)

TECHNICAL TSR 3.3.3.2 SURVEILLANCE REQUIREMENTS Verification by administrative means of the surveillance requirements (Continued) required elsewhere ensures the instrumentation channels satisfy nominal accuracy and reliability for power operation. Many of these surveillance requirements are CHANNEL CALIBRATIONS.

CHANNEL CALIBRATIONS are typically performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATION must be performed consistent with the assumptions of the Watts Bar setpoint methodology. The difference between the current as found values and the previous test as Left values must be consistent with the drift allowance used in the setpoint methodology.

The Frequency of 18 months is based upon the assumption of an 18 month calibration interval in the determination of the magnitude of sensor/transmitter drift in the setpoint methodology.

Four notes modify the surveillance requirements specified in Table 3.3.3-1.

Note 1 allows up to three parameters to be used for reactor power input into PDMS, but BEACON will only accept two options at any one time.

Note 2 allows the control bank position input to come from either the Demand Position Indication or the average of the individual Rod Position Indications.

Note 3 clarified that the CHANNEL CALIBRATION requirements do not apply to the secondary calorimetric power or average power range neutron flux power inputs.

Note 4 clarified that the calorimetric heat balance adjustment is not applicable to the average RCS Loop T power input.

(continued)

Watts Bar - Unit 2 B 3.3-10 Technical Requirements (developmental) B

Power Distribution Monitoring System (PDMS)

B 3.3.3 BASES (continued)

TECHNICAL TSR 3.3.3.3 SURVEILLANCE REQUIREMENTS The PDMS must be calibrated using an incore power distribution (Continued) measurement data set obtained above 25% RTP to ensure the accuracy of the calibration data set which is derived from the SPD and other input channels. The initial calibration in each fuel cycle must utilize incore flux measurements from at least 218 of the SPD elements meeting the distribution requirements provided in Table 3.3.3-1. The incore flux measurements in combination with at least the minimum channel inputs from Table 3.3.3-1 are used to generate the calibration data set, including nodal calibration factors. Subsequent PDMS calibrations require only

> 145 of the SPD elements meeting the distribution requirements listed in Table 3.3.3-1.

REFERENCES 1. WCAP-12472-P-A, BEACON Core Monitoring and Operations Support System, August 1994 (Addendum 2, April 2002).

2. 10 CFR 50.46

3. WCAP-11618, "MERITS Program-Phase II, Task 5, Criteria Application," including Addendum 1 dated April, 1989.

Watts Bar - Unit 2 B 3.3-11 Technical Requirements (developmental) B

Seismic Instrumentation B 3.3.4 B 3.3 INSTRUMENTATION B 3.3.4 Seismic Instrumentation BASES BACKGROUND The seismic instrumentation is made up of several instruments such as accelerometers, an accelerograph, recorders, etc. These instruments are placed in several appropriate locations throughout the plant in order to provide data on the seismic input to containment, data on the frequency, amplitude and phase relationship of the seismic response of the containment structure, and data on the seismic input to other Seismic Category I structures (Ref. 1).

The seismic instrumentation is used to promptly determine the nature and severity of a seismic event and to predict the impact (i.e., potential for damage) on nuclear power plant features which are important to safety.

This is required to permit comparison of the measured response to that used in the design basis for the unit to determine if plant shutdown is required pursuant to Appendix A of 10 CFR Part 100. The instrumentation is consistent with the recommendations of Reference 1.

The original seismic instrumentation was replaced with state of the art digital instrumentation in order to permit application of EPRI OBE exceedance criteria delineated in References 4 and 5. Use of these criteria is permitted by Reference 6 provided that upgraded instrumentation is used. The replacement instrumentation is capable of recording a seismic event and performing appropriate analyses of the recorded data to provide an immediate basis for determining whether an OBE exceedance has occurred. Reference 6 directs that this information must be evaluated within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after an event and a walkdown of critical plant features must be accomplished within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after an event in order to make a determination as to whether a plant shutdown is warranted.

(continued)

Watts Bar - Unit 2 B 3.3-12 Technical Requirements (developmental) A

Seismic Instrumentation B 3.3.4 BASES (continued)

APPLICABLE The OPERABILITY of the seismic instrumentation ensures that sufficient SAFETY capability is available to promptly determine the magnitude of a seismic ANALYSES event and to determine the impact on those features important to safety.

This capability is required to permit comparison of the measured response to that used in the design basis for the unit to determine if plant equipment inspection is required pursuant to Appendix A of 10 CFR Part 100 prior to restart. Seismic risks which appear as dominant sequences in PRAs occur for very severe earthquakes with magnitudes which are a factor of two or three above the Safe Shutdown Earthquake and Design Basis Earthquake. The Seismic Instrumentation System was not designed to function or to provide comparative information for such severe earthquakes. This instrumentation is more pertinent to determining the need to shut down following a seismic event and the ability to restart the plant after seismic events which are not risk contributors, and is therefore not of prime importance in risk dominant sequences (Ref. 2).

TR TR 3.3.4 requires that the seismic monitoring instrumentation which is shown in Table 3.3.4-1 shall be OPERABLE. This requirement ensures that an assessment can be made of the effects on the plant of earthquakes which may occur that exceed the design basis spectra for the Operating Basis Earthquake (Ref. 3).

APPLICABILITY Since the possibility of earthquakes is not MODE dependent, OPERABILITY of the seismic instrumentation is required at all times. The Applicability has been modified by a Note stating that the provisions of TR 3.0.3 do not apply.

ACTIONS A.1 The determination as to whether an OBE exceedance has occurred is made by comparing the calculated spectra for the event with the applicable design basis spectra for that building and location.

Reference 6 requires that this determination be made considering the data from instruments located on the Containment foundation. Therefore, the exceedance determination for WBN will be made using event data from 0-XT-52-75A in the Containment annulus. Data from this instrument is recorded at panel 0-R-113, which also contains the computer used to calculate the spectral content and the alarm panel used (continued)

Watts Bar - Unit 2 B 3.3-13 Technical Requirements (developmental) A

Seismic Instrumentation B 3.3.4 BASES ACTIONS A.1 (continued) to annunciate in the control room. These devices are the key components used to detect the event and make a shutdown determination. With one or more of these required seismic monitoring instruments inoperable for more than 30 days, the inoperability of the instruments must be documented in accordance with the Corrective Action Program.

With one or more of the remaining seismic instruments inoperable for more than 60 days, the inoperability of the instruments must be documented in accordance with the Corrective Action Program. A longer period of inoperability is allowed for these instruments since they are used only for evaluating plant condition following an event and not for input to the shutdown decision.

B.1, B.2, and B.3 When one or more seismic monitoring instruments actuate during a seismic event with greater than or equal to 0.01g ground acceleration, all of the Required Actions under Condition B must be completed. The data retrieved from the actuated instruments must be analyzed to determine the magnitude of the vibratory ground motion. The replacement digital instrumentation provides the capability to analyze the event data onsite and generate event spectra to be used in determining whether an OBE exceedance has occurred. If an OBE exceedance has occurred, Reference 6 directs that this evaluation should occur within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the event. Reference 6 also requires performance of a limited scope walkdown per Reference 7 to determine the extent of actual damage within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> following the event. The information provided by this walkdown and the spectral analysis are to be used in making a determination as to whether to proceed with plant shutdown. In addition, the seismic event must be documented in accordance with the Corrective Action Program.

B.4 and B.5 Each actuated monitoring instrument must be restored to OPERABLE status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Within 10 days of the actuation, a CHANNEL CALIBRATION must be performed on each actuated monitoring instrument. The Completion Time of 10 days to perform Required Action B.2 is reasonable and is based on engineering judgment.

(continued)

Watts Bar - Unit 2 B 3.3-14 Technical Requirements (developmental) A

Seismic Instrumentation B 3.3.4 BASES ACTIONS B.6 (continued)

Subsequent analysis must then be performed using data from the remaining seismic monitoring instruments to evaluate the plant response in comparison with previously generated design basis spectra at the locations of those instruments. The Completion Time of 14 days to perform Required Action B.6 is reasonable and based upon the typical time necessary to analyze data.

TECHNICAL The SRs for each seismic monitoring Function are identified by the SURVEILLANCE SRs column of Table 3.3.4-1.

REQUIREMENTS A Note has been added to the TSRs to clarify that Table 3.3.4-1 determines which SRs apply to which seismic monitoring instruments.

TSR 3.3.4.1 Performance of a CHANNEL CHECK on the seismic instrumentation once every 31 days ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is a check of external system status indications that the seismic monitoring equipment is in a state of readiness to properly function should an earthquake occur. A CHANNEL CHECK will detect gross system failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL OPERATIONAL TEST.

The Surveillance Frequency of 31 days is based on operating experience related to instrumentation systems, which demonstrates that gross instrumentation system failure in any 31 day interval is a rare event. The CHANNEL CHECK supplements the loss of power annunciation for the equipment in the auxiliary instrument room. The equipment in the auxiliary control room does not have a loss of power alarm but only provides supplemental data.

(continued)

Watts Bar - Unit 2 B 3.3-15 Technical Requirements (developmental) A

Seismic Instrumentation B 3.3.4 BASES TECHNICAL TSR 3.3.4.2 SURVEILLANCE REQUIREMENTS A CHANNEL OPERATIONAL TEST is to be performed on each required (continued) channel to ensure the entire channel will perform the intended function. A CHANNEL OPERATIONAL TEST is the comparison of the response of the instrumentation, including all components of the instrument, to a known signal. Although the seismic trigger is functionally checked, its setpoint is not verified. The 184 day Surveillance Frequency is based upon the known reliability of the monitoring instrumentation and has been shown to be acceptable through operating experience.

TSR 3.3.4.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor by comparing the response of the instrument to a known input on the sensor. This test verifies the capability of the seismic instrumentation to correctly determine the magnitude of a seismic event and evaluate the response of those features important to safety. The 18 month Surveillance Frequency is based upon operating experience and consistency with the typical industry refueling cycle.

REFERENCES 1. Regulatory Guide 1.12, "Instrumentation for Earthquakes.",

Revision 1, April 1974.

2. WCAP-11618, "MERITS Program-Phase II, Task 5, Criteria Application," including Addendum 1 dated April, 1989.

3. Watts Bar FSAR, Section 3.7.4, "Seismic Instrumentation Program."

4. EPRI NO-5930, July 1988, A Criterion for Determining Exceedance of the Operating Basis Earthquake.

5. EPRI TR-104239, June 1994, Seismic Instrumentation in Nuclear Power Plants for Response to OBE Exceedance: Guideline for Implementation.

6. Regulatory Guide 1.166, Pre-Earthquate Planning And Immediate Nuclear Power Plant Operator Post-Earthquake Actions, Revision 0, March 1997.

7. EPRI NP-6695, December 1989, Guidelines for Nuclear Plant Response to an Earthquake.

Watts Bar - Unit 2 B 3.3-16 Technical Requirements (developmental) A

Turbine Overspeed Protection B 3.3.5 B 3.3 INSTRUMENTATION B 3.3.5 Turbine Overspeed Protection BASES BACKGROUND Three types of overspeed protection mechanisms are provided to isolate main steam to the turbo-generator when the rated operating speed of 1800 rpm is exceeded. During normal speed-load control, the Analog Electro Hydraulic (AEH) Overspeed Protection Control (OPC) which is set at 1854 rpm (103 percent of rated speed) will rapidly close the governor and interceptor valves in case of an overspeed condition. Rotational speed is then maintained below this runback setpoint by moving the interceptor valves between the closed and open position until the reheater steam (steam between the high pressure turbine exhaust and the low pressure turbines) is dissipated. If the AEH control system is in the automatic mode, the governor valves will take over speed control and will maintain reference speed. However, if the AEH control system is in the manual mode (normally only at low power levels during startup), the turbine generator will coast down to turning gear operation, if no operator action is taken.

If for some reason the AEH OPC control system does not function and the turbine speed increases to 1980 rpm (110 percent of rated speed),

the mechanical overspeed mechanism will trip close all steam valves (throttle, governor, reheat, stop, and interceptor valves and prevent the turbine speed from exceeding 120 percent of rated speed. The unit will then coast down to turning gear operation.

In addition to these two control systems, an independent electrical overspeed trip is provided in the Analog Electro Hydraulic (AEH) Control System. If the turbine generator speed increases to 1998 rpm (111 percent of rated speed), all steam valves (as listed in the previous paragraph) will be tripped closed. This trip will be actuated by a contact output from the AEH controller which energizes a trip solenoid in the autostop oil fluid lines. Again, during the overspeed condition, turbine speed will remain below 120 percent of rated speed. The unit will then coast down to turning gear operation. (Ref. 1)

(continued)

Watts Bar - Unit 2 B 3.3-17 Technical Requirements (developmental) A

Turbine Overspeed Protection B 3.3.5 BASES (continued)

APPLICABLE The Turbine Overspeed Protection System trips the turbine to prevent the SAFETY generation of potentially damaging missiles from the turbine, in the event ANALYSES of a loss of the Turbine Speed Control System, or a transient. However, the turbine overspeed event is not a DBA (Ref. 2). Turbine Overspeed Protection is not assumed to function in the safety analyses.

TR This requirement is provided to ensure that the turbine overspeed protection instrumentation and the turbine speed control valves are OPERABLE and will protect the turbine from excessive overspeed.

Protection from turbine excessive overspeed is required since excessive overspeed of the turbine could generate potentially damaging missiles which could present a personnel and equipment hazard.

APPLICABILITY At least one Turbine Overspeed Protection System must be OPERABLE whenever the potential for turbine overspeed exists. Since steam may be admitted to the turbine in MODES 1, 2, or 3, the requirement is applicable in these MODES.

The Applicability has been modified by a Note stating that it is not applicable to MODES 2 and 3 when all main steam isolation valves are closed and all other steam flow paths to the turbine are isolated. Under these conditions, the potential for turbine overspeed does not exist.

ACTIONS A.1.1 and A.2.1 If one high pressure turbine steam inlet valve is inoperable, action must be taken to verify the two high pressure turbine steam inlet valves on the same steam chest which are opposite the inoperable valve are OPERABLE. The verification of operability (by testing) is needed to assure that these valves will close when the turbine is tripped. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Time was developed taking into account the time to reduce power and conduct the functional testing of the turbine steam inlet valves.

(continued)

Watts Bar - Unit 2 B 3.3-18 Technical Requirements (developmental) A

Turbine Overspeed Protection B 3.3.5 BASES ACTIONS A.1.2 (continued)

If one high pressure turbine steam inlet valve is inoperable, action must be taken to restore the inoperable valve to OPERABLE status. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time was developed taking into account the redundant capabilities afforded by the OPERABLE valves in the same steam chest and reasonable time for repairs. OPERABILITY is established by either having a fully functional valve or manually closing the otherwise inoperable valve. Closing the inoperable valve ensures total steam isolation to the high pressure turbine in the event of an overspeed condition, even with a single failure of another valve. Since the turbine must not have flow into non-adjacent zones (i.e., governor valves 1 and 3 or governor valves 2 and 4) due to possible turbine damage, isolation of a steam chest is precluded.

A.2.2 This alternative ensures total steam isolation to the high pressure turbine in the event that the inoperable valve cannot be closed. If it is determined through testing that another valve is also inoperable, then sufficient time would be available for an orderly turbine shutdown. This action is intended to prevent a condition involving a turbine trip coincident with multiple inoperable high pressure turbine steam inlet valves resulting in steam flow to the turbine. In this condition, insufficient time would be available for the operator to isolate the high speed turbine to avoid turbine overspeed. Since the turbine must not have flow through non-adjacent zones (i.e., governor valves 1 and 3 or governor valves 2 and 4) due to possible turbine damage, isolation of a steam chest is precluded. An additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (total of 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br />) are allowed for a power reduction, if necessary, in an orderly manner and without challenging plant systems.

A.3 Another alternative is to isolate the turbine from the steam supply using the Main Steam Isolation Valves (MSIV). This alternative assumes there may be partial leakage through the high pressure turbine steam inlet valves, or the steam path into the turbine cannot be isolated by the turbine inlet valves, thereby requiring closure of the MSIVs. This places the turbine in a condition where overspeed protection is not required.

Again, an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (total of 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br />) are allowed for a power reduction, if necessary, in an orderly manner and without challenging plant systems.

(continued)

Watts Bar - Unit 2 B 3.3-19 Technical Requirements (developmental) A

Turbine Overspeed Protection B 3.3.5 BASES ACTIONS B.1 (continued)

If one reheat stop valve or one reheat intercept valve in one or more low pressure turbine steam lines is inoperable, action must be taken to restore the inoperable valve(s) to OPERABLE status. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time was developed taking into account the redundant capabilities afforded by the OPERABLE valve in the same steam line(s) and reasonable time for repairs.

B.2 A first alternative to Required Action B.1 is to close at least one valve in the affected steam line(s). This places the low pressure steam line(s) with the inoperable valve(s) in a no flow condition. This ensures total steam isolation to the low pressure turbine(s) in the event of an overspeed condition, even with a single failure of another reheat stop valve or reheat intercept valve. An additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (total of 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br />) are allowed for a power reduction, if necessary, in an orderly manner and without challenging plant systems.

B.3 A second alternative is to isolate the turbine from the steam supply. This places the turbine in a condition where overspeed protection is not required. Again, an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (total of 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br />) are allowed for a power reduction, if necessary, in an orderly manner and without challenging plant systems.

C.1 If the Turbine Overspeed Protection System is inoperable for causes other than Condition A or Condition B, the turbine must be placed in a condition where overspeed protection is not required. This is accomplished by isolating the turbine from the steam supply system.

A Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is allowed to shutdown the turbine in an orderly manner and without challenging plant systems.

TECHNICAL TSR 3.3.5.1 SURVEILLANCE REQUIREMENTS The Turbine Overspeed Protection System testing requirements and frequencies are provided in Reference 3.

(continued)

Watts Bar - Unit 2 B 3.3-20 Technical Requirements (developmental) A

Turbine Overspeed Protection B 3.3.5 BASES (continued)

REFERENCES 1. Watts Bar FSAR, Section 10.2, "Turbine Generator."

2. WCAP-11618, "MERITS Program-Phase II, Task 5, Criteria Application," including Addendum 1 dated April, 1989.

3. Turbine Integrity Program With Turbine Overspeed Protection (TIPTOP).

Watts Bar - Unit 2 B 3.3-21 Technical Requirements (developmental) A

Loose-Part Detection System B 3.3.6 B 3.3 INSTRUMENTATION B 3.3.6 Loose-Part Detection System BASES BACKGROUND The Loose-Part Detection System consists of 12 sensors, a system cabinet, alarm units, and an audio monitor. The sensors are located in the six natural collection regions. These regions consist of the top and bottom plenums of the reactor vessel and the primary coolant inlet plenum to each steam generator. The entire system is described in Reference 1.

The Loose-Part Detection System provides the capability to detect acoustic disturbances indicative of loose parts within the Reactor Coolant System (RCS) pressure boundary. This system is provided to avoid or mitigate damage to RCS components that could occur from these loose parts. The Loose-Part Detection System Technical Requirement is consistent with the recommendations of Reference 2.

APPLICABLE The presence of a loose part in the RCS can be indicative of degraded SAFETY reactor safety resulting from failure or weakening of a safety-related ANALYSES component. A loose part, whether it be from a failed or weakened component, or from an item inadvertently left in the primary system during construction, refueling, or maintenance, can contribute to component damage and material wear by frequent impacting with other parts in the system. Also, a loose part increases the potential for control-rod jamming and for accumulation of increased levels of radioactive crud in the primary system (Ref. 2).

The Loose-Part Detection System provides the capability to detect loose parts in the RCS which could cause damage to some component in the RCS. Loose parts are not assumed to initiate any DBA, and the detection of a loose part is not required for mitigation of any DBA (Ref. 3).

(continued)

Watts Bar - Unit 2 B 3.3-22 Technical Requirements (developmental) B

Loose-Part Detection System B 3.3.6 BASES (continued)

TR TR 3.3.6 requires the Loose-Part Detection System to be OPERABLE.

This is necessary to ensure that sufficient capability is available to detect loose metallic parts in the RCS and avoid or mitigate damage to the RCS components. This requirement is provided in Reference 2.

APPLICABILITY TR 3.3.6 is required to be met in MODES 1 and 2 as stated in Reference 2. These MODES of applicability are provided in Reference 2.

The Applicability has been modified by a Note stating that the provisions of TR 3.0.3 do not apply.

ACTIONS A.1 With one or more Loose-Part Detection System channels inoperable for more than 30 days, document the inoperability of the channel in accordance with the Corrective Action Program.

TECHNICAL TSR 3.3.6.1 SURVEILLANCE REQUIREMENTS Performance of a CHANNEL CHECK for the Loose-Part Detection System once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or of even something more serious. CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

(continued)

Watts Bar - Unit 2 B 3.3-23 Technical Requirements (developmental) B

Loose-Part Detection System B 3.3.6 BASES TECHNICAL TSR 3.3.6.1 (continued)

SURVEILLANCE REQUIREMENTS Agreement criteria are determined by the plant staff based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the match criteria, it may be an indication that the sensor or the signal-processing equipment has drifted outside its limit.

The Surveillance and the Surveillance Frequency are provided in Reference 2.

TSR 3.3.6.2 A CHANNEL OPERATIONAL TEST is to be performed every 31 days on each required channel to ensure the entire channel will perform the intended function. This test verifies the capability of the Loose-Part Detection System to detect impact signals which would indicate a loose part in the RCS. The Surveillance and the Surveillance Frequency are provided in Reference 2.

TSR 3.3.6.3 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. The 18 month Surveillance Frequency is based upon operating experience and is consistent with the typical industry refueling cycle. The Surveillance and the Surveillance Frequency are provided in Reference 2.

REFERENCES 1. Watts Bar FSAR, Section 4.4.6, Digital Metal Impact Monitoring System (DMIMS-DXTM).

2. Regulatory Guide 1.133, "Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors."

3. WCAP-11618, "MERITS Program-Phase II, Task 5, Criteria Application," including Addendum 1 dated April, 1989.

Watts Bar - Unit 2 B 3.3-24 Technical Requirements (developmental) B

Reserved for Future Addition B 3.3.7 B 3.3 INSTRUMENTATION B 3.3.7 RESERVED FOR FUTURE ADDITION Watts Bar - Unit 2 B 3.3-25 Technical Requirements (developmental) B

Hydrogen Monitor B 3.3.8 B 3.3 INSTRUMENTATION B 3.3.8 Hydrogen Monitor BASES BACKGROUND A Hydrogen Monitor is provided to detect high hydrogen concentration conditions that represent a potential for containment breach from a hydrogen explosion. This variable is also useful in verifying the adequacy of postaccident mitigating actions. Hydrogen concentration may also be used to determine whether or not the Hydrogen Ignitors should be started or other action taken. Containment hydrogen instrumentation has a monitoring range of 0-10% (by volume) hydrogen concentration.

By rule change in 2003, 10 CFR 50.44 (Ref. 1) no longer defined a design basis Loss of Coolant Accident (LOCA) hydrogen release, and eliminated the requirements for hydrogen control systems to mitigate such a release.

The installation of Hydrogen Recombiners and/or vent and purge systems required by 50.44(b)(3) prior to revision in 2003 was intended to address the limited quantity and rate of hydrogen generation that was postulated from a design basis LOCA. The Commission found that this hydrogen release was not risk significant because the design-basis LOCA hydrogen release did not contribute to the conditional probability of a large release up to approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after the onset of core damage. In addition, these systems were ineffective at mitigating hydrogen releases from risk significant accident sequences that could threaten Reactor Building integrity. The Improved Standard Technical Specifications (ISTS) at the time stated that Hydrogen Recombiners met 10 CFR 50.36(c)(2)(ii)

Criterion 3 (accident mitigation). As stated in the rule change, since Hydrogen Recombiners are no longer required to respond to a LOCA, the Hydrogen Recombiners no longer meet Criterion 3 or any of the other criteria for retention in the Technical Specifications (TSs). Therefore, the new rule states that the requirements related to Hydrogen Recombiners currently in the ISTS no longer meet the criteria of 10 CFR 50.36(c)(2)(ii) for retention in the TSs and may be eliminated.

(continued)

Watts Bar - Unit 2 B 3.3-26 Technical Requirements (developmental) B

Hydrogen Monitor B 3.3.8 BASES BACKGROUND With the elimination of the design-basis LOCA hydrogen release, the (continued) Hydrogen Monitors are also no longer required to mitigate design basis accidents and, therefore, the Hydrogen Monitors do not meet the definition of a safety-related component as defined in 10 CFR 50.2 (Ref.

2). Regulatory Guide (RG) 1.97 (Ref. 3) Category 1 instrumentation is intended for key variables that most directly indicate the accomplishment of a safety function for design basis accident events. The Hydrogen Monitors no longer meet the definition of Category 1 in RG 1.97. As part of the rulemaking to revise 50.44 the Commission found that Category 3, as defined in RG 1.97, is an appropriate categorization for the Hydrogen Monitors because the monitors are required to diagnose beyond design basis accidents. Hydrogen monitoring is not the primary means of indicating a significant abnormal degradation of the reactor coolant pressure boundary and has been found to not be risk-significant.

Therefore, the rule making stated that hydrogen monitoring equipment requirements no longer meet the criteria of 50.36(c)(2)(ii) for retention in TSs and, therefore, may be removed from the TSs.

APPLICABLE As stated in the BACKGROUND section, the Hydrogen Monitor is no SAFETY longer required for mitigation of design basis accidents. Based on this, ANALYSES the Hydrogen Monitor does not meet the definition of a safety-related component. However, the elimination of Hydrogen Recombiners in accordance with Technical Specification Task Force (TSTF)-447, Rev. 1 (Ref. 4), was contingent on each licensee maintaining the capability to monitor hydrogen concentrations in the Reactor Building during beyond design basis accidents. This TR maintains that commitment (Ref. 5).

TR The Hydrogen Monitor is required to be OPERABLE to ensure that the necessary equipment will be available to monitor the hydrogen concentration within containment during significant beyond design-basis accident conditions (Ref. 5).

APPLICABILITY The Hydrogen Monitor is required to be OPERABLE in MODES 1, 2 and

3. In MODES 4, 5, and 6, unit conditions are such that the likelihood of an event that would require hydrogen monitoring is low; therefore, the monitor is not required to be OPERABLE in these MODES.

(continued)

Watts Bar - Unit 2 B 3.3-27 Technical Requirements (developmental) B

Hydrogen Monitor B 3.3.8 ACTIONS A.1 Seven days to restore the hydrogen monitor capability is reasonable given the requirement to be available for use in diagnostics during a beyond design basis event.

B.1 Condition B applies when the Required Action and associated Completion Time for Condition A are not met. This Required Action specifies that the failure to comply with the 7 day Completion Time must be documented in the Corrective Action Program so that the impact of the inoperable equipment with regard to continued plant operation may be evaluated.

Consideration should be given to alternate means, such as core damage assessments performed under the Severe Accident Management Guidelines during the extended period the Hydrogen Monitor is inoperable. During normal operations the probability of occurrence of a beyond design basis accident is low and therefore, continued plant operation should not be significantly impacted. However, the actions required to restore the inoperable monitor should be pursued in a manner that is commensurate with the component's importance to safety.

TECHNICAL SR 3.3.3.1 SURVEILLANCE REQUIREMENTS A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter with the necessary range and accuracy. The Frequency is based on operating experience and consistency with the typical industry refueling cycle.

(continued)

Watts Bar - Unit 2 B 3.3-28 Technical Requirements (developmental) B

Hydrogen Monitor B 3.

3.8 REFERENCES

1. 10 CFR 50.44, "Standards for Combustible Gas Control System in Light-Water-Cooled Power Reactors," October 16, 2003.

2. 10 CFR 50.2, Definition of Safety Related Structures, Systems, and Components.

3. Regulatory Guide 1.97, Revision 2, December 1980, "Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident."

4. TSTF-447, Revision 1, "Elimination of Hydrogen Recombiners and Change to Hydrogen and Oxygen Monitors."

5. Commitment (NCO080031001) made in TVAs letter dated September 4, 2008, to maintain a hydrogen monitoring system capable of diagnosing beyond design basis accidents.

6. Regulatory Guide 1.7, Revision 3, Control of Combustible Gas Concentrations in Containment.

Watts Bar - Unit 2 B 3.3-29 Technical Requirements (developmental) B