Text

License Amendment Request 24-06, Revision to Technical Specification 1.1 and Addition of 5.5.21 to Use Online Monitoring Methodology
	ML24366A169
Person / Time
Site:	Diablo Canyon
Issue date:	12/31/2024
From:	Shawn Williams; Pacific Gas & Electric Co
To:	; Office of Nuclear Reactor Regulation, Document Control Desk
References
	DCL-24-118
	Download: ML24366A169 (1)
	v • d • e

Pacific Gas and Electric Company..

PG&E Letter DCL-24-118 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Diablo Canyon Units 1 and 2 Docket No. 50-275, OL-DPR-80 Docket No. 50-323, OL-DPR-82 License Amendment Request 24-06 Sarooel Z. WIiiiams Ol1ector Nuclear Training &

Accreditation Oiablo Canyoo Power Plant Mal code 104/5/503 P.O. Box 56 Avila Beach, CA 93424 805.545,3431 Sam.\\'{iliamsi_ipge.com 10 CFR 50.90 Revision to Technical Specification 1.1 and Addition of 5.5.21 to Use Online Monitoring Methodology

Dear Commissioners and Staff:

Pursuant to 10 CFR 50.90, Pacific Gas and Electric Company (PG&E) hereby requests approval of the enclosed proposed amendment to Diablo Canyon Power Plant (DCPP), Unit 1 and 2 Technical Specification (TS) 1.1 "Definitions" and 5.5 "Programs and Manuals."

The proposed amendment revises the TS Section 1.1 Definitions section and adds a new "Online Monitoring Program" to the Section 5.5 programs section. PG&E proposes to use the Analysis and Measurement Services Corporation (AMS) online monitoring (OLM) methodology as the technical basis to switch from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency based on OLM results.

Approval of the proposed amendment is requested by September 30, 2025, to support use during the Unit 2 twenty-fifth refueling outage. Once approved, the amendment will be implemented within 90 days.

PG&E makes no regulatory commitments (as defined by NEI 99-04) in this letter.

This letter includes no revisions to existing regulatory commitments.

The enclosure to this letter contains the evaluation of the proposed change.

In accordance with site administrative procedures and the Quality Assurance Program, the proposed amendment has been reviewed by the Plant Staff Review Committee.

A member of the STARS (Strategic Teaming and Resource Sharingf Al lia nce Callaway

Diablo Canyon

Palo Verde

Wolf Creek

Document Control Desk Page 2 PG&E Letter DCL-24-118 Pursuant to 10 CFR 50.91, PG&E is notifying the State of California of this License Amendment Request by transmitting a copy of this letter and enclosure to the California Department of Public Health.

If you have any questions or require additional information, please contact James Morris, Manager, Regulatory Services, at 805-545-4609.

I state under penalty of perjury that the foregoing is true and correct.

Sincerely,

<iJJ]JJ{M Samuel Z. Williams Director, Nuclear Training & Accreditation kjse/51205913 Enclosure cc:

Oiablo Distribution Date cc/enc: Anthony Chu, Branch Chief, California Dept of Public Health Mahdi 0. Hayes, NRC Senior Resident Inspector Samson S. Lee, NRR Project Manager John D. Monninger, NRC Region IV Administrator A

member of the STARS (Strategic Teaming and Resource Sharing)

Alliance Callaway

Comanche Peak

Oiablo Canyon

Palo Verde

Wolf Creek

Enclosure PG&E Letter DCL-24-118 1

Evaluation of the Proposed Change

Subject:

License Amendment Request (LAR) 24-06, Revision to Technical Specification (TS) 1.1 and Addition of 5.5.21 to Use Online Monitoring (OLM)

Methodology

1.

SUMMARY

DESCRIPTION

2.

DETAILED DESCRIPTION

2.1 Background

2.2 System Design and Operation 2.3 Reason for the Proposed Change 2.4 Description of Proposed Change

3.

TECHNICAL EVALUATION 3.1 OLM Implementation Process Development 3.2 OLM Program Implementation 3.3 OLM Noise Analysis Implementation 3.4 Application Specific Action Items from AMS OLM TR

4.

REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 4.2 Precedent 4.3 Significant Hazards Consideration 4.4 Conclusions

5.

ENVIRONMENTAL CONSIDERATION

6.

REFERENCES ATTACHMENTS:

1. Proposed Technical Specification Changes (Mark-Up)

2. Revised Technical Specification Pages

3. TS Bases Changes Mark-Up (for information only)

Enclosure PG&E Letter DCL-24-118 2

EVALUATION

1.

SUMMARY

DESCRIPTION Pursuant to the provisions Section 50.90 of Title 10 Code of Federal Regulations (CFR),

Pacific Gas and Electric Company (PG&E) hereby requests a license amendment to the Diablo Canyon Power Plant (DCPP) License Nos. DPR-80 and DPR-82.

2.

DETAILED DESCRIPTION

2.1 Background

OLM technologies have been developed and validated for condition monitoring applications in a variety of process and power industries. This application of OLM is used to optimize maintenance of instrumentation and control (I&C) systems including online drift monitoring and assessment of dynamic failure modes of transmitters. AMS Topical Report (TR) AMS-TR-0720R2-A, Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters (References 1 and 2) focused on the application of OLM for monitoring drift of pressure, level, and flow transmitters in nuclear power plants. The TR addressed the following topics:

Advances in OLM implementation technology to extend transmitter calibration intervals

Experience with OLM implementation in nuclear facilities

Comparison between OLM results and manual calibrations

Transmitter failure modes that can be detected by OLM

Related regulatory requirements and industry standards and guidelines

Procedures for implementation of OLM methodology

Changes that must be made to existing technical specifications to adopt OLM AMS-TR-0720R2-A provided the NRC with the information needed to approve the AMS OLM methodology for implementation in nuclear power plants. The TR is intended to be used by licensees to support plant-specific TS changes to switch from time-based calibration frequency of pressure, level, and flow transmitters to a condition-based calibration frequency based on OLM results and to develop procedures to assess dynamic failure modes of pressure sensing systems using the noise analysis technique.

The NRC staff determined that the methodology outlined in the AMS OLM TR for applying OLM techniques to pressure, level, and flow transmitters can be used to provide reasonable assurance that required TS instrument calibration requirements for transmitters will be maintained. This determination was based on the NRC staff finding that OLM techniques: a) are effective at identifying instrument calibration drift during plant operation, b) provide an acceptable means of identifying when manual transmitter

Enclosure PG&E Letter DCL-24-118 3

calibration using traditional calibration methods are needed, and c) will maintain an acceptable level of performance that is traceable to calibration prime standards.

The NRC staff found that implementation of an OLM program in accordance with the approved AMS OLM TR provides an acceptable alternative to periodic manual calibration surveillance requirements upon implementation of the application-specific action items (ASAI) in Section 4.0 of its safety evaluation. The ASAIs are addressed in Section 3.4 of this enclosure.

2.2 System Design and Operation The transmitters to be included in the OLM Program provide input to the Reactor Trip Systems (RTS) and Engineered Safety Feature Actuation Systems (ESFAS) and are used for Post Accident Monitoring (PAM), the Remote Shutdown Systems, Pressurizer Power Operated Relief Valves (PORVs), Low Temperature Overpressure Protection (LTOP), and Reactor Coolant System (RCS) Leakage Detection Instrumentation.

The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and RCS pressure boundary during anticipated operational occurrences and to assist the ESFAS in mitigating accidents.

The RTS and related instrumentation are identified in TS Table 3.3.1-1, Reactor Trip System Instrumentation.

The ESFAS and related systems initiate necessary safety systems, based on the values of selected unit parameters, to protect against violating core design limits and the RCS pressure boundary, and to mitigate accidents. The ESFAS and related instrumentation are identified in TS Table 3.3.2-1, Engineered Safety Feature Actuation System Instrumentation.

The primary purpose of the PAM instrumentation is to display unit variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for Design Basis Accidents. The PAM instrumentation is identified in TS Table 3.3.3-1, Post Accident Monitoring Instrumentation.

The Remote Shutdown System provides the operator with sufficient instrumentation and controls to place and maintain the unit in a safe shutdown condition from a location other than the control room. This capability is necessary to protect against the possibility that the control room becomes inaccessible. The Remote Shutdown System instrumentation is addressed in Table 3.3.4-1, Remote Shutdown System Functions.

The Pressurizer PORVs maintain RCS pressure below the Pressurizer pressure high reactor trip setpoint during plant transients and minimize challenges to the pressurizer

Enclosure PG&E Letter DCL-24-118 4

safety valves. Pressurizer PORV instrumentation is identified in TS 3.4.11, Pressurizer Power Operated Relief Valves (PORVs),

The LTOP controls prevent RCS overpressure at low temperatures, so the integrity of the reactor coolant pressure boundary is not compromised by violating the pressure and temperature limits. LTOP provides the allowable combinations for pressure and temperature during cooldown, shutdown, and heatup to keep from violating the pressure and temperature limits. The LTOP instrumentation is identified in TS 3.4.12, Low Temperature Overpressure Protection LTOP System.

The RCS Leakage Detection Instrumentation provides the means for detecting RCS leakage. The containment, drywell, or reactor building sumps used to collect unidentified leakage is instrumented to detect increases above the normal fill rates. The RCS Leakage Detection Instrumentation is identified in TS 3.4.15, RCS Leakage Detection Instrumentation.

The RTS, ESFAS, PAM, Remote Shutdown System, Pressurizer PORVs, LTOP, and RCS Leakage Detection Instrumentation transmitters were evaluated in accordance with the methodology in AMS-TR-0720R2-A. The transmitters to be included in the OLM program and the bases for their selection can be found in AMS report DBC2410R0, OLM Amenable Transmitters Report for Diablo Canyon (Reference 3).

Switching from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency will not create any physical changes to the plant.

The changes will not impact how the plant operates. PG&E will use condition-based frequency to determine when transmitter calibrations are needed instead of performing calibrations based on a calendar frequency. Existing calibration methods will be used when it is determined that transmitter calibration is needed.

2.3 Reason for the Proposed Change PG&E is proposing to use the NRC-approved OLM methodology described in AMS-TR-0720R2-A. The use of the NRC-approved OLM methodology ensures that plant safety is maintained by demonstrating that transmitters are functioning correctly. The OLM methodology encompasses environmental and process conditions in the assessment of transmitter calibration.

The use of condition-based monitoring for transmitter calibration provides additional safety benefits, as described in AMS-TR-0720R2-A. The use of OLM will result in elimination of unnecessary transmitter calibration and associated potential opportunities for human errors. Elimination of unnecessary calibrations will also reduce calibration-induced damage to transmitters and other plant equipment. The use of OLM provides for timely detection of out-of-calibration transmitters. It eliminates occupational exposure

Enclosure PG&E Letter DCL-24-118 5

or potential human error opportunities related to calibration activities that were unnecessary.

2.4 Description of the Proposed Change PG&E proposes to change the DCPP definitions of CHANNEL CALIBRATION, ENGINEERED SAFETY FEATURE (ESF) RESPONSE TIME, and REACTOR TRIP SYSTEM (RTS) RESPONSE TIME in DCPP TS 1.1 Definitions.

Current definition of CHANNEL CALIBRATION A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass all devices in the channel required for channel OPERABILITY. Calibration of instrument channels with resistance temperature detectors (RTD) or thermocouple sensors may consist of an in-place qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping or total channel steps.

Proposed definition of CHANNEL CALIBRATION A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass all devices in the channel required for channel OPERABILITY (excluding transmitters in the TS 5.5.21 Online Monitoring Program). Calibration of instrument channels with resistance temperature detectors (RTD) or thermocouple sensors may consist of an in-place qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping or total channel steps.

Current definition of ESF RESPONSE TIME The ESF RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable.

The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC, or the components have been evaluated in accordance with an NRC approved methodology.

Enclosure PG&E Letter DCL-24-118 6

Proposed definition ESF RESPONSE TIME The ESF RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable.

The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC (including transmitters in the TS 5.5.21 Online Monitoring Program), or the components have been evaluated in accordance with an NRC approved methodology.

Current definition of RTS RESPONSE TIME The RTS RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its RTS trip setpoint at the channel sensor until loss of stationary gripper coil voltage. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC, or the components have been evaluated in accordance with an NRC approved methodology.

Proposed definition of RTS RESPONSE TIME The RTS RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its RTS trip setpoint at the channel sensor until loss of stationary gripper coil voltage. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC (including transmitters in the TS 5.5.21 Online Monitoring Program), or the components have been evaluated in accordance with an NRC approved methodology.

PG&E proposes to add a new TS 5.5.21 Online Monitoring Program for DCPP, as shown below (underline added for emphasis).

Enclosure PG&E Letter DCL-24-118 7

5.5.21 Online Monitoring Program This program provides controls to determine the need for calibration of pressure, level, and flow transmitters using condition monitoring based on drift analysis. It also provides a means for in-situ dynamic response assessment using the noise analysis technique to detect failure modes that are not detectable by drift monitoring.

The Online Monitoring Program must be implemented in accordance with AMS-TR-0720R2-A, Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters (proprietary version). The program shall include the following elements:

a. Implementation of online monitoring for transmitters that have been evaluated in accordance with an NRC approved methodology during the plant operating cycle.

1. Analysis of online monitoring data to identify those transmitters that require a calibration check and those that do not require a calibration check.

2. Performance of online monitoring using noise analysis to assess in-situ dynamic response of transmitters that can affect response time performance.

3. Calibration checks of identified transmitters no later than during the next scheduled refueling outage, and

4. Documentation of the results of the online monitoring data analysis.

b. Performance of a calibration check for any transmitter where the online monitoring was not implemented during the plant operating cycle no later than during the next scheduled refueling outage.

c. Performance of calibration checks for transmitters at the specified backstop frequencies.

d. The provisions of Surveillance Requirement 3.0.3 are applicable to the required calibration checks specified in items a.3, b, and c above.

The proposed TS changes are an adaptation from the illustrative changes presented in AMS-TR-0720R2-A that reduce the number of required plant-specific changes. The proposed Definition changes eliminated the need to modify the Channel Calibration and Response Time Surveillance Requirements. The proposed OLM Program description was reorganized to better align with the OLM implementation activities.

Enclosure PG&E Letter DCL-24-118 8

3.

TECHNICAL EVALUATION 3.1 OLM Implementation Process Development This section describes the steps that were performed to implement the OLM program for DCPP by following the steps identified in AMS-TR-0720R2-A Section 11.1.1. This work is documented in the AMS reports on OLM Amenable Transmitters (Reference 3) and OLM Analysis Methods and Limits (Reference 4).

The AMS report on OLM Amenable Transmitters addresses steps 1-6 from AMS-TR-0720R2-A Section 11.1.1. These steps were designed to arrive at a list of transmitters that can be included in an OLM program and determine how to obtain OLM data. The RTS, ESFAS, PAM, Remote Shutdown System, Pressurizer PORVs, LTOP, and RCS Leakage Detection transmitters to be included in the OLM program and the bases for their selection can be found in the AMS report on OLM Amenable Transmitters.

3.1.1 Determine if Transmitters are Amenable to OLM AMS-TR-0720R2-A Chapter 12 includes Table 12.4 that lists the nuclear grade transmitter models that are amenable to OLM. Any transmitter model that is not listed in this table should only be added to the OLM program if it can be shown by similarity analysis that its failure modes are the same as the listed transmitter models or otherwise detectable by OLM.

3.1.2 List Transmitters in Each Redundant Group This step establishes how to group the transmitters and evaluates the redundancy of each group.

3.1.3 Determine if OLM Data Covers Applicable Setpoints This step evaluates the OLM data for each group to determine if it covers applicable setpoints. Additional details are described in AMS-TR-0720R2-A Chapter 14.

3.1.4 Calculate Backstops A backstop, as described in AMS-TR-0720R2-A Chapter 13, must be established for each group of redundant transmitters amenable to OLM as a defense against common mode drift. The backstop identifies the maximum period between calibrations without calibrating at least one transmitter in a redundant group.

3.1.5 Establish Method of Data Acquisition OLM data is normally available in the plant computer or an associated data historian. If data is not available from the plant computer or historian, a custom data acquisition system including hardware and software must be employed to acquire the data.

Enclosure PG&E Letter DCL-24-118 9

3.1.6 Specify Data Collection Duration and Sampling Rate OLM data must be collected during startup, normal operation, and shutdown periods at the highest sampling rate by which the plant computer takes data. AMS-TR-0720R2-A Chapter 15 describes a process to determine the minimum sampling rate for OLM data acquisition to monitor for transmitter drift. AMS-TR-0720R2-A Chapter 8 describes a process to help determine the optimal sampling rate and minimum duration of OLM data collection.

AMS report on OLM Analysis Methods and Limits (Reference 4) address steps 7-8 from AMS-TR-0720R2-A Section 11.1.1. These steps address the calculation of the OLM limits and establish the methods of OLM data analysis.

3.1.7 Identify Data Analysis Methods OLM implementations must employ both simple averaging and parity space methods for data analysis as described in AMS-TR-0720R2-A Chapter 6.

3.1.8 Establish OLM Limits OLM limits must be established as described in AMS-TR-0720R2-A Chapter 7 for each group of redundant transmitters. Calculation of OLM limits must be based on combining uncertainties of components of each instrument channel from the transmitter in the field to the OLM data storage.

The AMS report on OLM Analysis Methods and Limits provides the OLM Limit calculations for the transmitters that are amenable to OLM at DCPP.

3.2 OLM Program Implementation This section summarizes the steps that must be followed to implement the OLM program for transmitter drift monitoring at DCPP in accordance with AMS-TR-0720R2-A. The steps described in this section are repeated at each operating cycle at DCPP to identify the transmitters that should be scheduled for a calibration check using data from periods of startup, normal operation, and shutdown. Additional details regarding the OLM Program Implementation discussed in this section are contained in the AMS report on OLM Drift Monitoring Program (Reference 5).

AMS-TR-0720R2-A Section 11.1.2 identifies eleven steps that must be followed each operating cycle to identify the transmitters that should be scheduled for a calibration check at the ensuing outage. Table 1 provides a mapping between AMS-TR-0720R2-A Section 11.1.2 and the LAR section where the item is addressed. Implementation of these steps is performed using the AMS Bridge and the AMS Calibration Reduction System (CRS) software programs that were developed by AMS under their 10 CFR Part 50 Appendix B software Quality Assurance (QA) program.

Enclosure PG&E Letter DCL-24-118 10 Table 1: Mapping to AMS-TR-0720R2-A Section 11.1.2 Item Step Step Number in Section 11.1.2 of AMS-TR-0720R2-A LAR Section 1

Retrieve OLM Data 9

3.2.1 2

Perform Data Qualification 10 3.2.2 3

Select Appropriate Region of Any Transient Data 11 3.2.3 4

Perform Data Analysis 12 3.2.4 5

Plot the Average Deviation for Each Transmitter 13 3.2.5 6

Produce a Table for Each Group That Combines All Results 14 3.2.6 7

Determine OLM Results for Each Transmitter 15 3.2.7 8

Address Uncertainties in the Unexercised Portion of Transmitter Range 16 3.2.8 9

Select Transmitters to Be Checked for Calibration as a Backstop 17 3.2.9 10 Perform Dynamic Failure Mode Assessment 18 3.2.10 11 Produce a Report of Transmitters Scheduled for Calibration Check 19 3.2.11 3.2.1 Retrieve OLM Data The first step in performing transmitter drift monitoring is to retrieve the OLM data. OLM data must be retrieved during periods of startup, normal operation, and shutdown. The method of data acquisition, data collection duration, sampling rate, and list of sensors whose data will be retrieved have been established as described in Section 3.1 of this document. The OLM data for DCPP will be retrieved using the AMS Bridge software which will retrieve data from the plant data historian and produce binary data files that are compatible with the AMS Calibration Reduction System (CRS) software or as a text files from the data historian or other data sources at the plant site, as applicable. AMS procedure OLM2201, Procedure for Online Monitoring Data Retrieval, has been developed for performing the data retrieval using the AMS Bridge software (Reference 6).

3.2.2 Perform Data Qualification OLM data retrieved from plant historians sometimes contains anomalies such as spikes, missing data, stuck data, and saturated data. The portion of data containing these anomalies should be excluded, filtered, and/or cleaned prior to analysis. The AMS CRS software provides functionality for these tasks and will be used to perform data qualification. AMS procedure OLM2202, Procedure for Performing Online Monitoring Data Qualification and Analysis, has been developed for performing data qualification and analysis using the AMS CRS software (Reference 7).

Enclosure PG&E Letter DCL-24-118 11 3.2.3 Select Appropriate Region of Any Transient Data The AMS CRS software provides means to select the regions of transient data as described in Step 11 of Section 11.1.2 of AMS-TR-0720R2-A and will be used to perform these selections.

This activity is part of OLM data analysis and is addressed in the data qualification and analysis procedure.

3.2.4 Perform Data Analysis Several tasks that must be performed in OLM data analysis for startup, normal operation, and shutdown data including:

1. Calculate the process estimate,

2. Calculate the deviation of each transmitter from the process estimate and plot the

outcome,

3. Partition the deviation data into region(s) by percent of span,

4. Calculate and plot the average deviation for each region versus percent of span,

5. Select appropriate process estimation techniques, filtering parameters, and remove any

outliers,

6. Determine if average deviations exceed OLM limits for any region, and

7. Review, document, and store the details and results of analysis.

The AMS CRS software provides functionality for performing these tasks and will be used to perform OLM data analysis. Detailed steps for performing OLM data analysis are provided in the data qualification and analysis procedure.

3.2.5 Plot the Average Deviation for Each Transmitter The AMS CRS software provides functionality for plotting the average deviation for each transmitter as described in Step 13 of Section 11.1.2 of AMS-TR-0720R2-A and will be used to perform this task. This activity is part of OLM data analysis and is addressed in detail in the data qualification and analysis procedure.

3.2.6 Produce a Table for Each Group That Combines All Results The AMS CRS software provides functionality for producing a table for each group of redundant transmitters that combines all results as described in Step 14 of Section 11.1.2 of AMS-TR-0720R2-A and will be used to perform this task. This activity is part of OLM data analysis and is addressed in detail in the data qualification and analysis procedure.

3.2.7 Determine OLM Results for Each Transmitter OLM results must be produced by the OLM analyst upon completion of data analysis for a complete operating cycle. The AMS CRS software provides functionality for producing these results as described in Step 15 of Section 11.1.2 of AMS-TR-0720R2-A and will be used to perform this task. This activity is part of OLM data analysis and is addressed in detail in the data qualification and analysis procedure.

Enclosure PG&E Letter DCL-24-118 12 3.2.8 Address Uncertainties in the Unexercised Portion of Transmitter Range The AMS CRS software provides functionality for addressing uncertainties in the unexercised portion of the transmitter ranged as described in Step 13 of Section 11.1.2 of AMS-TR-0720R2-A and will be used to perform this task. This activity is part of OLM data analysis and is addressed in detail in the data qualification and analysis procedure.

3.2.9 Select Transmitters to Be Checked for Calibration as a Backstop The AMS procedure OLM2202 is also used for maintaining the backstops for OLM. It provides detailed steps for selecting transmitters to be checked for calibration as a backstop as described in Step 17 of Section 11.1.2 of AMS-TR-0720R2-A.

3.2.10 Perform Dynamic Failure Mode Assessment As described in Step 18 of Section 11.1.2 of AMS-TR-0720R2-A, dynamic failure mode assessment must be performed using the noise analysis technique to cover dynamic failures that are not detectable by the OLM process for transmitter drift monitoring. Details on how this will be addressed for DCPP are described in LAR Section 3.3.

3.2.11 Produce a Report of Transmitters Scheduled for Calibration Check The results of OLM analysis must be compiled in a report and independently reviewed. The transmitters that have been flagged must be scheduled for a calibration check at the next opportunity. The AMS CRS software provides functionality for producing this report and will be used to perform this task. This activity is part of OLM data analysis and is addressed in detail in the data qualification and analysis procedure.

3.3 OLM Noise Analysis Implementation PG&E has eliminated transmitter response time testing requirements with NRC approval based, in part, on the performance of manual calibrations. Manual calibrations will not be performed except on transmitters that are flagged by OLM. The noise analysis methodology is provided in this document to enable licensees to assess the dynamic failure modes of transmitters that are not covered by the OLM process for transmitter drift monitoring.

This section summarizes the steps that must be followed to implement the noise analysis technique for transmitter dynamic failure mode assessment at DCPP in accordance with AMS-TR-0720R2-A. Additional details regarding the implementation of the noise analysis technique discussed in this section are provided in the AMS report on Noise Analysis Program (Reference 8).

As described in Section 11.3.3 of AMS-TR-0720R2-A, six steps must be followed to assess dynamic failure modes of pressure transmitters. Table 2 provides a mapping of the six steps in Section 11.3.3 of AMS-TR-0720R2-A and the section where they are addressed in this document. Implementation of these steps is performed using qualified noise data acquisition equipment and software programs that were developed by AMS under their 10 CFR Part 50 Appendix B software Quality Assurance (QA) program.

Enclosure PG&E Letter DCL-24-118 13 For DCPP, the transmitters with response time requirements have been identified in AMS report on OLM Amenable Transmitters (Reference 3).

Table 2: Mapping to AMS-TR-0720R2-A Section 11.3.3 Item Step Step Number in Section 11.3.3 of AMS-TR-0720R2-A LAR Section 1

Select Qualified Noise Data Acquisition Equipment 1

3.3.1 2

Connect Noise Data Acquisition Equipment to Plant Signals 2

3.3.2 3

Collect and Store Data for Subsequent Analysis 3

3.3.3 4

Screen Data for Artifacts and Anomalies 4

3.3.4 5

Perform Data Analysis 5

3.3.5 6

Review and Document Results 6

3.3.6 3.3.1 Select Qualified Noise Data Acquisition Equipment The first step in performing noise analysis is to select qualified noise data acquisition equipment. This equipment must have a valid calibration traceable to the National Institute of Standards and Technology and meet a set of performance criteria detailed Step 1 of Section 11.3.3 of AMS-TR-0720R2-A. The equipment used to acquire data at DCPP will be the AMS OLM data acquisition system which is comprised of hardware and software that has been developed and tested using AMS 10 CFR Part 50 Appendix B hardware and software QA program.

3.3.2 Connect Noise Data Acquisition Equipment to Plant Signals AMS Procedure NPS1501, Procedure for Noise Data Collection from Plant Sensors, is used for the connection of the noise data acquisition equipment for performing noise analysis testing (Reference 9). This procedure identifies the locations for connection to process signals as well as the qualified personnel who may connect the data acquisition system at these locations. The noise data acquisition system should be connected to as many transmitters as allowed by the number of data acquisition channels and the plant procedures. Multiple transmitters (e.g., up to 32) can be tested simultaneously to reduce the test time. Each data acquisition channel must be connected to the transmitter current loop as shown in Section 11.3.3 of AMS-TR-0720R2-A.

3.3.3 Collect and Store Data for Subsequent Analysis The noise data should be collected during normal plant operation at full temperature, pressure, and flow and analyzed in real time or stored to be analyzed later. However,

Enclosure PG&E Letter DCL-24-118 14 noise data taken at other conditions is acceptable as long as there is enough process fluctuation with sufficient amplitude and frequency content to drive the transmitters to reveal their dynamic characteristics. Noise data collection will be performed using AMS OLM Data Acquisition software which has been developed and tested using AMS software V&V program which conforms to 10 CFR Part 50 Appendix B. The use of this software for noise data acquisition is addressed in the AMS procedure for performing noise analysis testing (Reference 9).

3.3.4 Screen Data for Artifacts and Anomalies Noise data may contain anomalies that must be excluded, filtered, and/or cleaned prior to data analysis. AMS Procedure NAR2201, Procedure for Performing Dynamic Failure Mode Assessment Using Noise Analysis, is used for performing noise analysis data analysis (Reference 10) and will be performed using AMS noise analysis software.

3.3.5 Perform Data Analysis Noise data analysis will be performed as described in Section 11.3.3 Step 5 in AMS-TR-0720R2-A using AMS noise analysis software. General data analysis steps for the analyst as well as detailed steps for performing noise data analysis are also provided in the AMS procedure for performing noise analysis data analysis (Reference 10).

3.3.6 Review and Document Results Results of noise data analysis will be reviewed and approved by qualified personnel and documented in a report. This process is detailed in the AMS procedure for performing noise analysis data analysis (Reference 10).

3.4 Application Specific Action Items from AMS OLM TR The NRC approval of the AMS OLM TR required implementation of the ASAIs in Section 4.0 of its safety evaluation. Five ASAIs were identified, and each is addressed below.

ASAI 1 - Evaluation and Proposed Mark-up of Existing Plant Technical Specifications When preparing a license amendment request to adopt OLM methods for establishing calibration frequency, licensees should consider markups that provide clear requirements for accomplishing plant operations, engineering data analysis, and instrument channel maintenance. Such TS changes would need to include appropriate markups of the TS tables describing limiting conditions for operation and surveillance requirements, the technical basis for the changes, and the administrative programs section.

Enclosure PG&E Letter DCL-24-118 15 Response to ASAI 1: The proposed changes to the DCPP TS are identified in Section 2.4 and shown in Attachments 1 and 2. The proposed changes modify applicable Definitions and add a new program for OLM in the Administrative Controls. No changes to the TS tables describing Limiting Conditions for Operation or Surveillance Requirements were necessary.

ASAI 2 - Identification of Calibration Error Source When determining whether an instrument can be included in the plant OLM program, the licensee shall evaluate calibration error source in order to account for the uncertainty due to multiple instruments used to support the transfer of transmitter signal data to the data collection system.

Calibration errors identified through OLM should be attributed to the transmitter until testing can be performed on other support devices to correctly determine the source of calibration error and reallocate errors to these other loop components.

Response to ASAI 2: Calibration error is evaluated as part of the calculation of OLM limits as described in Section 3.1.8. The calculation of OLM limits is based on combining uncertainties of components of each instrument channel from the transmitter in the field to the OLM data storage. The OLM data assessment methods described in Section 3.2.7 include guidance to consider calibration errors identified through OLM as coming from the transmitter until testing can be performed on other support devices to correctly determine the source of calibration error and reallocate errors to these other loop components.

ASAI 3 - Response Time Test Elimination Basis If the plant has eliminated requirements for performing periodic RT testing of transmitters to be included in the OLM program, then the licensee shall perform an assessment of the basis for RT test elimination to determine if this basis will remain valid upon implementation of the OLM program and to determine if the RT test elimination will need to be changed to credit the OLM program rather than the periodic calibration test program.

Response to ASAI 3: PG&E previously eliminated requirements for performing periodic response time testing based on the periodic calibration of transmitters that are proposed to be included in the OLM program. For transmitters in which the AMS OLM is applied, PG&E propose to change the basis for response time test elimination to the methodology described in Section 3.3, which is based on the noise analysis methodology described in Section 11.3 of the AMS OLM TR.

Enclosure PG&E Letter DCL-24-118 16 ASAI 4 - Use of Calibration Surveillance Interval Backstop In its application for a license or license amendment to incorporate OLM methods for establishing calibration surveillance intervals, applicants or licensees should describe how they intend to apply backstop intervals as a means for mitigating the potential that a process group could be experiencing undetected common mode drift characteristics.

Response to ASAI 4: The PG&E OLM program for DCPP adopts the calibration surveillance interval backstop methods described in Section 3.2.9, which is based on the backstop methodology described in Section 13 of the AMS OLM TR.

The Updated Final Safety Analysis Report (UFSAR) for DCPP will be modified to add the use of AMS-TR-0720R2-A to the appropriate parts of Chapter 7. The use of OLM to switch from time-based calibration frequency of pressure, level, and flow transmitters to a condition-based calibration frequency based on OLM results will be added to the appropriate parts of UFSAR Chapter 7, including a list of transmitters included in the OLM program. The appropriate parts of UFSAR Chapter 7 will also be changed to describe the use of OLM assess dynamic failure modes of pressure-type sensing systems using the noise analysis technique to support the continued elimination of transmitter response time testing.

ASAI 5 - Use of Criteria other than in AMS OLM TR for Establishing Transmitter Drift Flagging Limit In its application for a license or license amendment to incorporate OLM methods for establishing calibration surveillance intervals, applicants or licensees should describe whether they intend to adopt the criteria within the AMS OLM TR for flagging transmitter drift or whether they plan to use a different methodology for determining this limit.

Response to ASAI 5: The PG&E OLM program for DCPP adopts the two averaging techniques (i.e., simple average and parity space) described in Section 6 of the AMS OLM TR for flagging transmitter drift.

Enclosure PG&E Letter DCL-24-118 17

4.

REGULATORY EVALUATION 4.1 Applicable Regulatory Requirements/Criteria 10 CFR 50.36 Technical Specifications. Part (3) of this regulation sets the governing requirements for the inclusion of Surveillance Requirements in the Technical Specifications included in the Operating License for a commercial nuclear power plant.

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

PG&E proposes to use the AMS OLM methodology for DCPP as the technical basis to support plant-specific Technical Specification changes to switch from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency based on OLM results.

10 CFR Part 50 Appendix A. General Design Criterion 21, Protection System Reliability and Testability, requires, in part, that plant protection systems be designed to permit periodic testing during reactor operation, including a capability to test channels independently to determine failures and losses of redundancy that may have occurred.

Criterion 21, Protection System Reliability and Testability. The protection system shall be designed for high functional reliability and in-service testability commensurate with the safety functions to be performed.

Redundancy and independence designed into the protection system shall be sufficient to assure that (1) no single failure results in loss of the protection function and (2) removal from service of any component or channel does not result in loss of the required minimum redundancy unless the acceptable reliability of operation of the protection system can be otherwise demonstrated. The protection system shall be designed to permit periodic testing of its functioning when the reactor is in operation, including a capability to test channels independently to determine failures and losses of redundancy that may have occurred.

DCPP, Units 1 and 2 were designed to meet the intent of the Atomic Energy Commission (now the NRC) General Design Criteria (GDC) for Nuclear Power Plant Construction Permits, published in July 1967. The DCPP construction permit for units 1 and 2 were issued in April 1968 and December 1970. Conformance with the applicable

Enclosure PG&E Letter DCL-24-118 18 1967 General Design Criteria (GDC) discussed below is described in Section 3.1.7 of the DCPP Units 1 and 2 UFSAR.

The DCPP UFSAR Section 7.3.1.13 uses General Design Criterion 38, 1967 in lieu of 10 CFR Part 50 Appendix A General Design Criterion 21. It specifies that ESFAS is designed to provide high functional reliability and ready testability.

PG&E proposes to use the AMS OLM methodology for DCPP as the technical basis to support plant-specific TS changes to switch from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency based on OLM results.

The OLM methodology is also proposed to be used to assess dynamic failure modes of pressure sensing systems.

Regulatory Guide 1.118, Revision 3. Regulatory Guide 1.118, Revision 3, Periodic Testing of Electric Power and Protection Systems, endorses with qualification the IEEE Standard 338-1987, IEEE Standard Criteria for the Periodic Surveillance Testing of Nuclear Power Generating Station Safety Systems.

PG&E proposes to use the AMS OLM methodology as the technical basis to support plant-specific TS changes to switch from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency based on OLM results.

IEEE Standard 338-1977. This standard contains the following requirements related to calibration:

6.3.3 Channel Calibration Verification Tests. A channel calibration verification test should prove that with a known precise input, the channel gives the required output, analog, or bistable. Additionally, in analog channels, linearity and hysteresis may be checked. If the required output is achieved, the test is acceptable. If the required output is not achieved (for example, the bistable trip did not occur at the required set point or the analog output was out of tolerance) or saturation or foldover is observed and adjustment or alignment of gain, bias, trip set, etc., is required, the test is unacceptable. Adjustment or alignment procedures are maintenance activities and are outside the scope of this standard. Test results, however, shall be recorded in accordance with ANSI/ANS 3.2-1982, or the equivalent. Following maintenance or other appropriate disposition of the unacceptable results, a successful rerun of the channel calibration verification test shall be performed.

6.5.2 Changes to Test Interval. The effect of testing intervals on performance of equipment shall be reevaluated periodically to determine if the interval used is an effective factor in maintaining equipment in an operational status. The following shall be considered:

History of equipment performance, particularly experienced failure rates and potential significant increases in failure rates.

Enclosure PG&E Letter DCL-24-118 19

Corrective action associated with failures.

Performance of equipment in similar plants or environment, or both.

Plant design changes associated with equipment.

Detection of significant changes of failure rates.

Test intervals may be changed to agree with plant operational modes provided it can be shown that such changes do not adversely affect desired performance of the equipment being tested. Tests need not be performed on systems or equipment when they are not required to be operable or are tripped. If tests are not conducted on such systems, they shall be performed prior to returning the system to operation.

PG&E proposes to use the AMS OLM methodology for DCPP as the technical basis to support plant-specific TS changes to switch to time-based surveillance frequency for channel calibrations to a condition-based calibration frequency based on the OLM results for a given transmitter.

IEEE Standard 338-2012. This standard contains the following requirements related to calibration:

5.3.3.2 On-line monitoring. On-line monitoring (OLM) techniques enable the determination of portions of an instrument channels status during plant operation. This methodology is an acceptable input for establishing calibration frequency of those monitored portions of instrument channels without adversely affecting reliability.

Continuous monitoring shall be employed, e.g., through the plant computer. Periodic manual testing is either a maintenance or surveillance task and is not on-line monitoring.

On-line monitoring shall ensure that setpoint calculation assumptions and the safety analysis assumptions remain valid.

PG&E proposes to use the AMS OLM methodology for DCPP as the technical basis to support plant-specific TS changes to switch to time-based surveillance frequency for channel calibrations to a condition-based calibration frequency based on the OLM results for a given transmitter.

4.2 Precedent This license amendment request is based the NRC-approved Analysis and Measurement Services Corporation Topical Report AMS-TR-0720R2, Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters (References 1 and 2). The NRC previously approved a license amendment request submitted by Southern Nuclear Operating Company for Vogtle

Enclosure PG&E Letter DCL-24-118 20 Electric Generating Plant Units 1 and 2 to extend calibration intervals of nuclear plant pressure transmitters using AMS-TR-0720R2 (References 11 and 12).

4.3 Significant Hazards Consideration PG&E has evaluated the proposed changes to the DCPP Technical Specifications (TS) using the criteria in 10 CFR 50.92 and has determined that the proposed changes do not involve a significant hazards consideration.

The proposed changes revise the following TSs:

DCPP TS 1.1 definitions for CHANNEL CALIBRATION, ESF RESPONSE TIME, and RTS RESPONSE TIME.

The proposed changes add new Online Monitoring Program TSs, as shown below:

DCPP TS 5.5.21 Online Monitoring Program PG&E proposes to use online monitoring (OLM) methodology as the technical basis to switch from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency based on OLM results. Switching from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency will not create any physical changes to the plant. The use of the NRC-approved OLM methodology ensures that plant safety is maintained by demonstrating that transmitters are functioning correctly.

PG&E has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, Issuance of amendment, as discussed below:

1. Does the proposed change involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The proposed change uses online monitoring (OLM) methodology as the technical basis to switch from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency based on OLM results.

Switching from time-based surveillance frequency for channel calibrations to a condition-based calibration frequency will not create any physical changes to the plant. The use of the NRC-approved OLM methodology ensures that plant safety is maintained by demonstrating that transmitters are functioning correctly.

Enclosure PG&E Letter DCL-24-118 21 The proposed changes do not adversely affect accident initiators or precursors, and do not alter the design assumptions, conditions, or configuration of the plant or the way the plant is operated or maintained.

Therefore, the proposed changes do not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed change create the possibility of a new or different accident from any accident previously evaluated?

Response: No.

The change does not involve a physical alteration of the plant (i.e., no new or different type of equipment will be installed) or a change in the methods governing normal plant operation. Existing calibration methods will be used when the need for transmitter calibration is determined. The change does not alter assumptions made in the safety analysis but ensures that the transmitters operate as assumed in the accident analysis. The proposed change is consistent with the safety analysis assumptions.

Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any previously evaluated.

3. Does the proposed change involve a significant reduction in a margin of safety?

Response: No.

The change does not involve a physical alteration of the plant (i.e., no new or different type of equipment will be installed) or a change in the methods governing normal plant operation. The change does not alter assumptions made in the safety analysis but ensures that the transmitters operate as assumed in the accident analysis. The proposed change is consistent with the safety analysis assumptions.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above evaluation, PG&E concludes that the proposed change does not involve a significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and accordingly, a finding of no significant hazards consideration is justified.

4.4 Conclusions In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in

Enclosure PG&E Letter DCL-24-118 22 the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

5.

ENVIRONMENTAL CONSIDERATION PG&E has evaluated the proposed amendment and has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or a significant increase in the amounts of any effluents that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure.

Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(c)(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

6.

REFERENCES

1. Analysis and Measurement Services Corporation letter to NRC dated August 20, 2021, Submittal of -A Version of Analysis and Measurement Services Corporation Topical Report AMS-TR-0720R2, Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters (Docket No.

99902075), (ADAMS Accession No. ML21235A493)

2. NRC Form 896, AMS Topical Report -A Verification, dated September 22, 2021 (ADAMS Accession No. ML21237A490)

3. AMS Report DBC2410R0, OLM Amenable Transmitters Report for Diablo Canyon

4. AMS Report DBC2411R0, OLM Analysis Methods and Limits Report for Diablo Canyon

5. AMS Report DBC2412R0, OLM Drift Monitoring Program Report for Diablo Canyon

6. AMS Procedure OLM2201, Procedure for Online Monitoring Data Retrieval, December 2022

7. AMS Procedure OLM2202, Procedure for Performing Online Monitoring Data Qualification and Analysis, August 2024

8. AMS Report DBC2413R0, OLM Noise Analysis Program Report for Diablo Canyon

Enclosure PG&E Letter DCL-24-118 23

9. AMS Procedure NPS1501, Procedure for Noise Data Collection from Plant Sensors, March 2015

10. AMS Procedure NAR2201, Procedure for Performing Dynamic Failure Mode Assessment Using Noise Analysis, August 2024

11. Southern Nuclear Operating Company letter NL-22-0764 to NRC dated December 21, 2022, License Amendment Request to Revise Technical Specification 1.1 and Add 5.5.23 to Use Online Monitoring Methodology, (ADAMS Accession No. ML22355A588)

12. NRC letter to Southern Nuclear Operating Company dated June 15, 2023, Vogtle Electric Generating Plant, Units 1 And 2 - Issuance of Amendments Regarding Revision to Technical Specifications to Use Online Monitoring Methodology, (ADAMS Accession No. ML23115A149)

Enclosure PG&E Letter DCL-24-118 Proposed Technical Specification Changes (Mark-Up)

Definitions 1.1 DIABLO CANYON - UNITS 1 & 2 Rev 13 Page 1 of 27 Tab_1!0u3r13.DOC 0530.1058 1.0 USE AND APPLICATION 1.1 Definitions

NOTE------------------------------------------------------------

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

Term Definition ACTIONS ACTIONS shall be that part of a Specification that prescribes Required Actions to be taken under designated Conditions within specified Completion Times.

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

AXIAL FLUX DIFFERENCE (AFD)

AFD shall be the difference in normalized flux signals between the top and bottom halves of an excore neutron detector.

CHANNEL CALIBRATION A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass all devices in the channel required for channel OPERABILITY. Calibration of instrument channels with resistance temperature detectors (RTD) or thermocouple sensors may consist of an in-place qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping or total channel steps.

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

(continued) 1.1-1 Unit 1 - Amendment No. 135, Unit 2 - Amendment No. 135, INSERT:

(excluding transmitters in the TS 5.5.21 Online Monitoring Program)

Definitions 1.1 DIABLO CANYON - UNITS 1 & 2 Rev 13 Page 5 of 27 Tab_1!0u3r13.DOC 0530.1058 1.1 Definitions (continued)

ENGINEERED SAFETY FEATURE (ESF) RESPONSE TIME The ESF RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC, or the components have been evaluated in accordance with an NRC approved methodology.

LEAKAGE LEAKAGE shall be:

a.

Identified LEAKAGE 1.

LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water injection or leakoff), that is captured and conducted to collection systems or a sump or collecting tank; 2.

LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or (continued) 1.1-3a Unit 1 - Amendment No. 135,155,156,192,244, Unit 2 - Amendment No. 135,155,156,193,245, INSERT:

(including transmitters in the TS 5.5.21 Online Monitoring Program)

Definitions 1.1 DIABLO CANYON - UNITS 1 & 2 Rev 13 Page 7 of 27 Tab_1!0u3r13.DOC 0530.1058 1.1 Definitions (continued)

PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR)

The PTLR is the unit specific document that provides the reactor vessel pressure and temperature limits, including heatup and cooldown rates, and the power operated relief valve (PORV) lift settings and arming temperature associated with the Low Temperature Overpressurization Protection (LTOP) System, for the current reactor vessel fluence period. These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 5.6.6.

QUADRANT POWER TILT RATIO (QPTR)

QPTR shall be the ratio of the maximum upper excore detector calibrated output to the average of the upper excore detector calibrated outputs, or the ratio of the maximum lower excore detector calibrated output to the average of the lower excore detector calibrated outputs, whichever is greater.

RATED THERMAL POWER (RTP)

RTP shall be a total reactor core heat transfer rate to the reactor coolant of 3411 MWt for each unit.

REACTOR TRIP SYSTEM (RTS) RESPONSE TIME The RTS RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its RTS trip setpoint at the channel sensor until loss of stationary gripper coil voltage. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC, or the components have been evaluated in accordance with an NRC approved methodology.

SHUTDOWN MARGIN (SDM)

SDM shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming:

a.

All rod cluster control assemblies (RCCAs) are fully inserted except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn. With any RCCA not capable of being fully inserted, the reactivity worth of the RCCA must be accounted for in the determination of SDM; and b.

In MODES 1 and 2, the fuel and moderator temperatures are changed to the hot zero power temperatures.

(continued) 1.1-5 Unit 1 - Amendment No. 135,143, 170, 244, Unit 2 - Amendment No. 135, 171, 245, INSERT:

(including transmitters in the TS 5.5.21 Online Monitoring Program)

Programs and Manuals 5.5 DIABLO CANYON - UNITS 1 & 2 Rev 38 Page 19 of 28 Tab_5!0u3r38.DOC 0530.1143 5.5 Programs and Manuals (continued) 5.5.20 Risk Informed Completion Time (RICT) Program This program provides controls to calculate a RICT and must be implemented in accordance with NEI 06-09-A, Revision 0, "Risk-Managed Technical Specifications (RMTS) Guidelines."

The program shall include the following:

a.

The RICT may not exceed 30 days; b.

A RICT may only be utilized in MODE 1 and 2; c.

When a RICT is being used, any change to the plant configuration, as defined in NEI 06-09-A, Appendix A, must be considered for the effect on the RICT.

1.

For planned changes, the revised RICT must be determined prior to implementation of the change in configuration.

2.

For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

3.

Revising the RICT is not required If the plant configuration change would lower plant risk and would result in a longer RICT.

d.

For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:

1.

Numerically accounting for the increased possibility of CCF in the RICT calculation; or 2.

Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.

e.

The risk assessment approaches and methods shall be acceptable to the NRC.

The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods approved for use with this program, or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.

5.0-17b Unit 1 - Amendment No. 245, Unit 2 - Amendment No. 247, INSERT:

New TS 5.5.21 here

INSERT 5.5.21 Online Monitoring Program This program provides controls to determine the need for calibration for pressure, level, and flow transmitters using condition monitoring based on drift analysis. It also provides a means for in-situ dynamic response assessment using the noise analysis technique to detect failure modes that are not detectable by drift monitoring.

The Online Monitoring Program must be implemented in accordance with AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters (proprietary version). The program shall include the following elements:

a.

Implementation of online monitoring for transmitters that have been evaluated in accordance with the NRC approved methodology during the plant operating cycle.

1.

Analysis of online monitoring data to identify those transmitters that require a calibration check and those that do not require a calibration

check, 2.

Performance of online monitoring using noise analysis to assess in-situ dynamic response of transmitters that can affect response time performance, 3.

Calibration checks of identified transmitters no later than during the next scheduled refueling outage, and 4.

Documentation of the results of the online monitoring data analysis.

b.

Performance of a calibration checks of any transmitter where the online monitoring was not implemented during the plant operating cycle no later than during the next scheduled refueling outage.

c.

Performance of calibration checks for transmitter at the specified backstop frequencies.

d.

The provisions of Surveillance Requirement 3.0.3 are applicable to the required calibration checks specified in items a.3, b, and c above.

D

Enclosure PG&E Letter DCL-24-118 Revised Technical Specification Pages Remove Page Insert Page 5.0-17b 5.0-17b 5.0-17c

Definitions 1.1 DIABLO CANYON - UNITS 1 & 2 Rev 13 Page 1 of 27 Tab_1!0u3r13.doc 1113.1118 1.0 USE AND APPLICATION 1.1 Definitions

NOTE------------------------------------------------------------

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

Term Definition ACTIONS ACTUATION LOGIC TEST AXIAL FLUX DIFFERENCE (AFD)

CHANNEL CALIBRATION CHANNEL CHECK ACTIONS shall be that part of a Specification that prescribes Required Actions to be taken under designated Conditions within specified Completion Times.

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

AFD shall be the difference in normalized flux signals between the top and bottom halves of an excore neutron detector.

A CHANNEL CALIBRATION shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameter that the channel monitors. The CHANNEL CALIBRATION shall encompass all devices in the channel required for channel OPERABILITY (excluding transmitters in the TS 5.5.21 Online Monitoring Program). Calibration of instrument channels with resistance temperature detectors (RTD) or thermocouple sensors may consist of an in-place qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel. The CHANNEL CALIBRATION may be performed by means of any series of sequential, overlapping or total channel steps.

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

(continued) 1.1-1 Unit 1 - Amendment No. 135, Unit 2 - Amendment No. 135,

Definitions 1.1 DIABLO CANYON - UNITS 1 & 2 Rev 13 Page 5 of 27 Tab_1!0u3r13.doc 1113.1118 1.1 Definitions (continued)

ENGINEERED SAFETY FEATURE (ESF) RESPONSE TIME LEAKAGE The ESF RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its ESF actuation setpoint at the channel sensor until the ESF equipment is capable of performing its safety function (i.e., the valves travel to their required positions, pump discharge pressures reach their required values, etc.). Times shall include diesel generator starting and sequence loading delays, where applicable. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC (including transmitters in the TS 5.5.21 Online Monitoring Program), or the components have been evaluated in accordance with an NRC approved methodology.

LEAKAGE shall be:

a.

Identified LEAKAGE 1.

LEAKAGE, such as that from pump seals or valve packing (except reactor coolant pump (RCP) seal water injection or leakoff), that is captured and conducted to collection systems or a sump or collecting tank; 2.

LEAKAGE into the containment atmosphere from sources that are both specifically located and known either not to interfere with the operation of leakage detection systems or not to be pressure boundary LEAKAGE; or (continued) 1.1-3a Unit 1 - Amendment No. 135,155,156,192, 244, Unit 2 - Amendment No. 135,155,156,193, 245,

Definitions 1.1 DIABLO CANYON - UNITS 1 & 2 Rev 13 Page 7 of 27 Tab_1!0u3r13.doc 1113.1118 1.1 Definitions (continued)

PRESSURE AND TEMPERATURE LIMITS REPORT (PTLR)

QUADRANT POWER TILT RATIO (QPTR)

RATED THERMAL POWER (RTP)

REACTOR TRIP SYSTEM (RTS) RESPONSE TIME The PTLR is the unit specific document that provides the reactor vessel pressure and temperature limits, including heatup and cooldown rates, and the power operated relief valve (PORV) lift settings and arming temperature associated with the Low Temperature Overpressurization Protection (LTOP) System, for the current reactor vessel fluence period. These pressure and temperature limits shall be determined for each fluence period in accordance with Specification 5.6.6.

QPTR shall be the ratio of the maximum upper excore detector calibrated output to the average of the upper excore detector calibrated outputs, or the ratio of the maximum lower excore detector calibrated output to the average of the lower excore detector calibrated outputs, whichever is greater.

RTP shall be a total reactor core heat transfer rate to the reactor coolant of 3411 MWt for each unit.

The RTS RESPONSE TIME shall be that time interval from when the monitored parameter exceeds its RTS trip setpoint at the channel sensor until loss of stationary gripper coil voltage. The response time may be measured by means of any series of sequential, overlapping, or total steps so that the entire response time is measured. In lieu of measurement, response time may be verified for selected components provided that the components and methodology for verification have been previously reviewed and approved by the NRC (including transmitters in the TS 5.5.21 Online Monitoring Program), or the components have been evaluated in accordance with an NRC approved methodology.

SHUTDOWN MARGIN (SDM)

SDM shall be the instantaneous amount of reactivity by which the reactor is subcritical or would be subcritical from its present condition assuming:

a.

All rod cluster control assemblies (RCCAs) are fully inserted except for the single RCCA of highest reactivity worth, which is assumed to be fully withdrawn. With any RCCA not capable of being fully inserted, the reactivity worth of the RCCA must be accounted for in the determination of SDM; and b.

In MODES 1 and 2, the fuel and moderator temperatures are changed to the hot zero power temperatures.

(continued) 1.1-5 Unit 1 - Amendment No. 135,143, 170, 244, Unit 2 - Amendment No. 135, 171, 245,

Programs and Manuals 5.5 DIABLO CANYON - UNITS 1 & 2 Rev 38 Page 19 of 29 Tab_5!0u3r38.doc 1113.1604 5.5 Programs and Manuals (continued) 5.5.20 Risk Informed Completion Time (RICT) Program This program provides controls to calculate a RICT and must be implemented in accordance with NEI 06-09-A, Revision 0, "Risk-Managed Technical Specifications (RMTS) Guidelines."

The program shall include the following:

a.

The RICT may not exceed 30 days; b.

A RICT may only be utilized in MODE 1 and 2; c.

When a RICT is being used, any change to the plant configuration, as defined in NEI 06-09-A, Appendix A, must be considered for the effect on the RICT.

1.

For planned changes, the revised RICT must be determined prior to implementation of the change in configuration.

2.

For emergent conditions, the revised RICT must be determined within the time limits of the Required Action Completion Time (i.e., not the RICT) or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after the plant configuration change, whichever is less.

3.

Revising the RICT is not required If the plant configuration change would lower plant risk and would result in a longer RICT.

d.

For emergent conditions, if the extent of condition evaluation for inoperable structures, systems, or components (SSCs) is not complete prior to exceeding the Completion Time, the RICT shall account for the increased possibility of common cause failure (CCF) by either:

1.

Numerically accounting for the increased possibility of CCF in the RICT calculation; or 2.

Risk Management Actions (RMAs) not already credited in the RICT calculation shall be implemented that support redundant or diverse SSCs that perform the function(s) of the inoperable SSCs, and, if practicable, reduce the frequency of initiating events that challenge the function(s) performed by the inoperable SSCs.

e.

The risk assessment approaches and methods shall be acceptable to the NRC.

The plant PRA shall be based on the as-built, as-operated, and maintained plant; and reflect the operating experience at the plant, as specified in Regulatory Guide 1.200, Revision 2. Methods to assess the risk from extending the Completion Times must be PRA methods approved for use with this program, or other methods approved by the NRC for generic use; and any change in the PRA methods to assess risk that are outside these approval boundaries require prior NRC approval.

(continued) 5.0-17b Unit 1 - Amendment No. 245, Unit 2 - Amendment No. 247,

Programs and Manuals 5.5 DIABLO CANYON - UNITS 1 & 2 Rev 38 Page 20 of 29 Tab_5!0u3r38.doc 1113.1604 5.5 Programs and Manuals (continued) 5.5.21 Online Monitoring Program This program provides controls to determine the need for calibration for pressure, level, and flow transmitters using condition monitoring based on drift analysis. It also provides a means for in-situ dynamic response assessment using the noise analysis technique to detect failure modes that are not detectable by drift monitoring.

The Online Monitoring Program must be implemented in accordance with AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters (proprietary version). The program shall include the following elements:

a.

Implementation of online monitoring for transmitters that have been evaluated in accordance with the NRC approved methodology during the plant operating cycle.

1.

Analysis of online monitoring data to identify those transmitters that require a calibration check and those that do not require a calibration

check, 2.

Performance of online monitoring using noise analysis to assess in-situ dynamic response of transmitters that can affect response time performance, 3.

Calibration checks of identified transmitters no later than during the next scheduled refueling outage, and 4.

Documentation of the results of the online monitoring data analysis.

b.

Performance of a calibration checks of any transmitter where the online monitoring was not implemented during the plant operating cycle no later than during the next scheduled refueling outage.

c.

Performance of calibration checks for transmitter at the specified backstop frequencies.

d.

The provisions of Surveillance Requirement 3.0.3 are applicable to the required calibration checks specified in items a.3, b, and c above.

5.0-17c Unit 1 - Amendment No.

Unit 2 - Amendment No.

Enclosure PG&E Letter DCL-24-118 TS Bases Changes Mark-Up (for information only)

RTS Instrumentation B 3.3.1 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 60 of 173 Tab_B3!3u3r14.DOC 0424.1543 BASES SURVEILLANCE REQUIREMENTS SR 3.3.1.8 (continued)

Once the unit is in MODE 3, this surveillance is no longer required. If power is to be maintained < P-10 for more than 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or < P-6 for more than 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months , then the testing required by this surveillance must be performed prior to the expiration of the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months or 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months limit, as applicable. These time limits are reasonable, based on operating experience, to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-6) for the periods discussed above. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.9 SR 3.3.1.9 is the performance of a TADOT. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification requires elaborate bench calibration and is accomplished during the CHANNEL CALIBRATION.

SR 3.3.1.10 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 CALIBRATIONS must be performed consistent with the assumptions of the DCPP 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.

Whenever an RTD is replaced in Functions 6, 7, or 14, the next required CHANNEL CALIBRATION of the RTDs is accomplished by an inplace cross calibration that compares the other sensing elements with the recently installed sensing element.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable.

(continued)

Insert:

Alternately, the Frequency for checking the calibration of pressure, level, and flow transmitters may be determined in accordance with the Online Monitoring Program implemented in accordance with AMS-TR-0720R2-A (Ref. 35) and TS 5.5.21, Online Monitoring Program.

RTS Instrumentation B 3.3.1 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 64 of 173 Tab_B3!3u3r14.DOC 0424.1543 BASES SURVEILLANCE REQUIREMENTS SR 3.3.1.16 (continued)

Response time may be verified by actual response time tests in any series of sequential, overlapping or total channel measurements, or by the summation of allocated sensor response times with actual response time tests on the remainder of the channel. Allocations for sensor response times may be obtained from: (1) historical records based on acceptable response time tests (hydraulic, noise, or power interrupt tests), (2) inplace, onsite, or offsite (e.g. vendor) test measurements, or (3) utilizing vendor engineering specifications. WCAP-13632-P-A Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" (Ref. 8) provides the basis and methodology for using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP.

Response time verification for other sensor types must be demonstrated by test.

WCAP-14036-P-A, Revision 1, Elimination of Periodic Protection Channel Response Time Tests, provides the basis and methodology for using allocated signal processing and actuation logic response times in the overall verification of the protection system channel response time. The allocations for sensor, signal conditioning, and actuation logic response times must be verified prior to placing the component in operational service and reverified following maintenance work that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. Specific components identified in the WCAP may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter.

The response time may be verified for components that replace the components that were previously evaluated in Ref. 8 and Ref.

27, provided that the components have been evaluated in accordance with the NRC approved methodology as discussed in to TSTF-569, Methodology to Eliminate Pressure Sensor and Protection Channel (for Westinghouse Plants only)

Response Time Testing, (Ref. 34).

For Westinghouse supplied replacement SSPS printed circuit boards (PCBs), Westinghouse has determined that the bounding times and conclusions made in WCAP-14036-P-A apply to the worst-case combination of the new-design PCBs and the original (replaced) PCBs.

This applies to reactor trip and safeguards (ESF) functions. Refer to Reference 32, Section 10, for more information.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

(continued)

Insert:

Alternately, the use of the allocated RTS RESPONSE TIME for transmitters in the Online Monitoring Program is supported by the performance of ONLINE MONITORING using the 'noise analysis' technique to detect dynamic failures modes that can affect transmitter response time.

RTS Instrumentation B 3.3.1 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 66 of 173 Tab_B3!3u3r14.DOC 0424.1543 BASES REFERENCES (continued)

17. WCAP-11082, "Westinghouse Setpoint Methodology for Protection Systems, Diablo Canyon Units 1 and 2, 24 Month Fuel Cycle Evaluation and Replacement Steam Generator," September 2007.

18. NSP-1-20-13F Unit 1 "Turbine Auto Stop Low Oil Pressure."

19. NSP-2-20-13F Unit 2 "Turbine Auto Stop Low Oil Pressure."

20. J-110 "24 Month Fuel Cycle Allowable Value Determination /

Documentation and ITDP Uncertainty Sensitivity."

21. IEEE Std. 338-1977.

22. License Amendment 61/60, May 23, 1991.

23. Westinghouse Technical Bulletin ESBU-TB-92-14-R1, Decalibration Effects of Calorimetric Power Measurements on the NIS High Power Reactor Trip at Power Levels less than 70% RTP, dated February 6, 1996.

24. DCPP NSSS Calculation N-212, Revision 1.

25. License Amendments 157/157, June 2, 2003.

26. WCAP-12472-P-A, "BEACON Core Monitoring and Operations Support System," August 1994.

27. WCAP-14036-P-A, Revision 1, Elimination of Periodic Protection Channel Response Time Tests, October 1998.

28. WCAP-14333-P-A, Revision 1, Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times, October 1998.

29. WCAP-15376-P-A, Revision 1, Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times, March 2003.

30. WCAP-11394-P-A, "Methodology For The Analysis of the Dropped Rod Event," January, 1990

31. License Amendments 205/206, April 29, 2009

32. WCAP-16769-P Revision 1, "Westinghouse SSPS Universal Logic Board Replacement Summary Report 6D30225G01/G02/G03/G04," July 2008.

33. WCAP-12472-P-A, Addendum 4, Revision 0, "BEACON Core Monitoring and Operations Support System," September 2012

34. Attachment 1 to TSTF-569, Methodology to Eliminate Pressure Sensor and Protection Channel (for Westinghouse Plants only)

Response Time Testing, August 2019.

Insert:

35. AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters."

ESFAS Instrumentation B 3.3.2 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 120 of 173 Tab_B3!3u3r14.DOC 0424.1543 BASES SURVEILLANCE REQUIREMENTS SR 3.3.2.9 (continued)

Whenever an RTD is replaced in Function 6.d., the next required CHANNEL CALIBRATION of the RTDs is accomplished by an inplace cross calibration that compares the other sensing elements with the recently installed sensing element.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable.

The next two paragraphs apply only to Function 5.b, an SL-LSSS function, in TS Table 3.3.2-1.

SR 3.3.2.9 for Function 5.b is modified by two notes as identified in Table 3.3.2-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the AV. Evaluation of instrument performance will verify that the instrument will continue to behave in accordance with safety analysis assumptions. The purpose of the assessment is to ensure confidence in the instrument performance prior to returning the instrument to service. The performance of these channels will be evaluated under the DCPP Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition for continued OPERABILITY. The second Note requires that the as-left setting for the instrument be returned to within the as-left tolerance of the NTSP. Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures, the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the SL and/or Analytical Limit is maintained. If the as-left instrument setting cannot be returned to a setting within the as-left tolerance, then the instrument channel shall be declared inoperable.

The second Note also requires that the NTSP and the methodologies for calculating the as-left and the as-found tolerances be in the ECGs.

(continued)

Insert:

Alternately, the Frequency for checking the calibration of pressure, level, and flow transmitters may be determined in accordance with the Online Monitoring Program implemented in accordance with AMS-TR-0720R2-A (Ref. 22) and TS 5.5.21, Online Monitoring Program.

ESFAS Instrumentation B 3.3.2 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 122 of 173 Tab_B3!3u3r14.DOC 0424.1543 BASES SURVEILLANCE REQUIREMENTS SR 3.3.2.10 (continued)

Response time Testing requirements," dated January 1996, provides the basis and the methodology of using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP. Response time verification for other sensor types must be demonstrated by test.

WCAP-14036-P-A, Revision 1, Elimination of Periodic Protection Channel Response Time Tests, provides the basis and methodology for using allocated signal processing and actuation logic response times in the overall verification of the protection system channel response time. The allocations for sensor, signal conditioning, and actuation logic response times must be verified prior to placing the component in operational service and reverified following maintenance work that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. Specific components identified in the WCAP may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter.

The response time may be verified for components that replace the components that were previously evaluated in Ref. 11 and Ref. 16, provided that the components have been evaluated in accordance with the NRC approved methodology as discussed in to TSTF-569, Methodology to Eliminate Pressure Sensor and Protection Channel (for Westinghouse Plants only)

Response Time Testing, (Ref. 21).

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that clarifies that the turbine driven AFW pump is tested within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after reaching 650 psig in the SGs.

SR 3.3.2.11 SR 3.3.2.11 is the performance of a TADOT as described in SR 3.3.2.8, except that it is performed for the P-4 Reactor Trip Interlock. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note that excludes verification of setpoints during the TADOT. The Function tested has no associated setpoint.

(continued)

Insert:

Alternately, the use of the allocated ESF RESPONSE TIME for transmitters in the Online Monitoring Program is supported by the performance of ONLINE MONITORING using the 'noise analysis' technique to detect dynamic failures modes that can affect transmitter response time.

ESFAS Instrumentation B 3.3.2 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 124 of 173 Tab_B3!3u3r14.DOC 0424.1543 BASES REFERENCES (continued)

9.

WCAP-13878, "Reliability of Potter & Brumfield MDR Relays",

June 1994.

10. WCAP-14117, "Reliability Assessment of Potter and Brumfield MDR Series Relays."

11. WCAP-13632-P-A, Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements," January 1996.

12. WCAP-11082, "Westinghouse Setpoint Methodology for Protection Systems, Diablo Canyon Units 1 and 2, 24 Month Fuel Cycle and Replacement Steam Generator Evaluation," September 2007.

13. Calculation J-54, "Nominal Setpoint Calculation for Selected PLS Setpoints."

14. J-110, "24 Month Fuel Cycle Allowable Value Determination /

Documentation and ITDP Uncertainty Sensitivity."

15. License Amendment 61/60, May 23, 1991.

16. WCAP-14036-P-A, Revision 1, Elimination of Periodic Protection Channel Response Time Tests, October 1998.

17. WCAP-14333-P-A, Revision 1, Probabilistic Risk Analysis of the RPS and ESFAS Test Times and Completion Times, October 1998.

18. WCAP-15376-P-A, Revision 1, Risk-Informed Assessment of the RTS and ESFAS Surveillance Test Intervals and Reactor Trip Breaker Test and Completion Times, March 2003.

19. 10 CFR 50.55a(h), "Protection and Safety Systems."

20. WCAP-16294-NP-A, Rev. 1, "Risk-Informed Evaluation of Changes to Technical Specification Required Action Endstates for Westinghouse NSSS PWRs," June 2010.

21. Attachment 1 to TSTF-569, Methodology to Eliminate Pressure Sensor and Protection Channel (for Westinghouse Plants only)

Response Time Testing, August 2019.

Insert:

22. AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters."

PAM Instrumentation B 3.3.3 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 140 of 173 Tab_B3!3u3r14.DOC 0424.1543 BASES SURVEILLANCE REQUIREMENTS SR 3.3.3.2 (continued) responds with the necessary range and accuracy, the test must verify that the proper indication is received when the valve is stroked to the fully closed position. Verification of intermediate position or actual percentage closed is not required, however, for OPERABILITY, the position indication must be able to communicate the proper isolation status of the containment penetration. Adjustments to the channel may be done as part of this surveillance or through other controlled instructions. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES

1.

UFSAR, Section 7.5.

2.

Regulatory Guide 1.97, Revision 3.

3.

NUREG-0737, Supplement 1, "TMI Action Items."

4.

Supplemental Safety Evaluation Report 14.

5.

Supplemental Safety Evaluation Report 31.

Insert:

The Frequency for checking the calibration of pressure, level, and flow transmitters may be determined in accordance with the Online Monitoring Program implemented in accordance with AMS-TR-0720R2-A (Ref. 6) and TS 5.5.21, Online Monitoring Program.

Insert:

6. AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters."

Remote Shutdown System B 3.3.4 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 147 of 173 Tab_B3!3u3r14.DOC 0424.1543 BASES SURVEILLANCE REQUIREMENTS SR 3.3.4.2 (continued)

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.4.3 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

The channel calibration is not applicable to the RTB indication.

Whenever an RTD is replaced in Function 3.a or 3.b, the next required CHANNEL CALIBRATION of the RTDs is accomplished by an inplace cross calibration that compares the other sensing elements with the recently installed sensing element.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES

1.

10 CFR 50, Appendix A, GDC 19, 1971 (associated with 1967 GDC 11 per UFSAR Appendix 3.1A.).

2.

SAPN 50610685 Tech Spec Bases B3.3.4

3.

DCP Number: 1000025004 - Unit 2 - NFPA 805 Hot Shutdown Panel Modification

4.

DCP Number: 1000024930 - Unit 1 - NFPA 805 Hot Shutdown Panel Modification Insert:

5. AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters."

Insert:

The Frequency for checking the calibration of pressure, level, and flow transmitters may be determined in accordance with the Online Monitoring Program implemented in accordance with AMS-TR-0720R2-A (Ref. 5) and TS 5.5.21, Online Monitoring Program.

Pressurizer PORVs B 3.4.11 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 59 of 112 Tab_B3!4u3r14.DOC 0530.1024 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.11.3 Verifying OPERABILITY of the PG&E Design Class I nitrogen supply for the Class I PORVs may be accomplished by:

a.

Isolating and venting the normal air supply, and

b.

Verifying that any leakage of the PG&E Design Class I backup nitrogen system is within its limits, and

c.

Operating the Class I PORVs through one complete cycle of full travel.

Operating the solenoid nitrogen control valves and check valves on the nitrogen supply system and operating the Class I PORVs through one complete cycle of full travel ensures the nitrogen backup supply for the Class I PORV operates properly when called upon. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.4.11.4 Performance of a COT is required on each required Class I PORV to verify and, as necessary, adjust its lift setpoint. PORV actuation could depressurize the RCS and is not required.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.4.11.5 Performance of a CHANNEL CALIBRATION on each required Class I PORV actuation channel is required to adjust the whole channel so that it responds and the valve opens within the required range and accuracy to known input.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES

1.

Not Used.

2.

UFSAR, Sections 15.2 and 15.4.

3.

ASME, Code for Operation and Maintenance of Nuclear Power Plants, 2001 Edition including 2002 and 2003 Addenda.

4.

Generic Letter 90-06, "Resolution of Generic Issue 70, 'Power-Operated Relief Valve and Block Valve Reliability,' and generic issue 94, 'Additional Low-Temperature Overpressure Protection for Light-Water Reactors,' Pursuant to 10 CFR 50.54(f)," June 25, 1990.

Insert:

5. AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters."

Insert:

The Frequency for checking the calibration of pressure, level, and flow transmitters may be determined in accordance with the Online Monitoring Program implemented in accordance with AMS-TR-0720R2-A (Ref. 5) and TS 5.5.21, Online Monitoring Program.

LTOP System B 3.4.12 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 73 of 112 Tab_B3!4u3r14.DOC 0530.1024 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.12.9 Performance of a CHANNEL CALIBRATION on each required Class I PORV actuation channel is required to adjust the whole channel so that it responds and the valve opens within the required range and accuracy to known input.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES

1.

10 CFR 50, Appendix G.

2.

Generic Letter 88-11.

3.

Not Used

4.

UFSAR, Chapter 5.

5.

10 CFR 50, Section 50.46.

6.

10 CFR 50, Appendix K.

7.

Generic Letter 90-06.

8.

Not Used

9.

ASME Code Case N-514.

10. AR A0625429

11. AR A0589860

12. Diablo Canyon Power Plant Pressure and Temperature Limits Report

13. PG&E Letter DCL-16-028, License Amendment Request 16-02, License Amendment Request To Revise Technical Specification 3.4.12, "Low Temperature Overpressure Protection (LTOP)

System", dated March 23, 2016.

14. SAPN 50970026-12 Insert:

15. AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters."

Insert:

The Frequency for checking the calibration of pressure, level, and flow transmitters may be determined in accordance with the Online Monitoring Program implemented in accordance with AMS-TR-0720R2-A (Ref. 15) and TS 5.5.21, Online Monitoring Program.

RCS Leakage Detection Instrumentation B 3.4.15 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 98 of 112 Tab_B3!4u3r14.DOC 0530.1024 BASES (continued)

ACTIONS (continued)

Required Action F.2 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 4. This Note prohibits the use of LCO 3.0.4.a to enter MODE 4 during startup with the LCO not met.

However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 4, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.

The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SR 3.4.15.1 SR 3.4.15.1 requires the performance of a CHANNEL CHECK of the required containment atmosphere radioactivity monitors. The check gives reasonable confidence that the channels are operating properly.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.4.15.2 SR 3.4.15.2 requires the performance of a CHANNEL FUNCTIONAL TEST (CFT) on the required containment atmosphere radioactivity monitors. The test ensures that the monitors can perform their function in the desired manner including alarm functions. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.4.15.3, SR 3.4.15.4, and SR 3.4.15.5 These SRs require the performance of a CHANNEL CALIBRATION for each of the RCS leakage detection instrumentation channels. The calibration verifies the accuracy of the instrument string, including the instruments located inside containment. The Frequency of 24 months (except for the containment atmosphere particulate and gaseous radioactivity monitors which have a frequency of 18 months) is consistent with refueling cycle and considers channel reliability. Again, operating experience has proven that this Frequency is acceptable.

Insert:

The Frequency for checking the calibration of pressure, level, and flow transmitters may be determined in accordance with the Online Monitoring Program implemented in accordance with AMS-TR-0720R2-A (Ref. 9) and TS 5.5.21, Online Monitoring Program.

RCS Leakage Detection Instrumentation B 3.4.15 DIABLO CANYON - UNITS 1 & 2 Rev 14B Page 99 of 112 Tab_B3!4u3r14.DOC 0530.1024 BASES REFERENCES

1.

10 CFR 50, Appendix A, Section IV, GDC 16, 1967.

2.

Regulatory Guide 1.45, Revision 0, "Reactor Coolant Pressure Boundary Leakage Detection Systems," May 1973.

3.

UFSAR, Section 5.2.7.

4.

NUREG-609, "Asymmetric Blowdown Loads on PWR Primary System," 1981.

5.

Generic Letter 84-04, "Safety Evaluation of Westinghouse Topical Reports Dealing with Elimination of Postulated Breaks in PWR Primary Main Loops."

6.

UFSAR, Appendix 3.6B.

7.

NUREG-1061, Volume 3, Report of the U.S. Nuclear Regulatory Commission Piping Review Committee, 1984.

8.

WCAP-16294-NP-A, Rev. 1, "Risk-Informed Evaluation of Changes to Technical Specification Required Action Endstates for Westinghouse NSSS PWRs," June 2010.

Insert:

9. AMS-TR-0720R2-A, "Online Monitoring Technology to Extend Calibration Intervals of Nuclear Plant Pressure Transmitters."

v t e Letter Sequence Request
EPID:L-2024-LLA-0179, (Approved, Closed)
Initiation Request Acceptance Administration Questions Answers Results Approval, Approval, Approval Other: ML25135A434
MONTHYEAR2025-02-07 [Table View]

DCL-24-118, License Amendment Request 24-06, Revision to Technical Specification 1.1 and Addition of 5.5.21 to Use Online Monitoring Methodology

Text

Dear Commissioners and Staff:

Subject:

SUMMARY

2.1 Background

SUMMARY

2.1 Background

Navigation menu

DCL-24-118, License Amendment Request 24-06, Revision to Technical Specification 1.1 and Addition of 5.5.21 to Use Online Monitoring Methodology

Text

Dear Commissioners and Staff:

Subject:

SUMMARY

2.1 Background

SUMMARY

2.1 Background

Navigation menu

Search