ML13060A210

From kanterella
Jump to navigation Jump to search

Issuance of Amendment No. 179, Revise Technical Specification 3.3.8.1, Loss of Power Instrumentation, to Extend Frequency of Surveillance Requirement 3.3.8.1.3 and Revise Allowable Values of Certain Functions
ML13060A210
Person / Time
Site: River Bend Entergy icon.png
Issue date: 03/29/2013
From: Wang A
Plant Licensing Branch IV
To:
Entergy Operations
Wang A
References
TAC ME7767
Download: ML13060A210 (26)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 March 29, 2013 Vice President, Operations Entergy Operations, Inc.

River Bend Station 5485 US Highway 51 N St. Francisville, LA 70775

SUBJECT:

RIVER BEND STATION, UNIT 1 -ISSUANCE OF AMENDMENT RE:

DEGRADED VOLTAGE SURVEILLANCE FREQUENCY EXTENSION AND ALLOWABLE VALUE CHANGES (TAC NO. ME7757)

Dear Sir or Madam:

The Commission has issued the enclosed Amendment No. 179 to Facility Operating License No. NPF-47 for the River Bend Station, Unit 1. The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated December 8, 2011, as supplemented by letters dated April 11, May 2, and September 5,2012, and January 9 and March 8, 2013.

The amendment revises Surveillance Requirement (SR) 3.3.8.1.3 for calibration of loss of power instrumentation to extend the frequency of the SR from 18 to 24 months, and revises certain allowable values in TS 3.3.8.1, "Loss of Power Instrumentation."

A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely,

~W~6 Alan B. Wang, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-458

Enclosures:

1. Amendment No. 179 to NPF-47
2. Safety Evaluation cc w/encls: Distribution via Listserv

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555*0001 ENTERGY GULF STATES LOUISIANA. LLC AND ENTERGY OPERATIONS, INC.

DOCKET NO. 50-458 RIVER BEND STATION, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 179 License No. NPF-47

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

A. The application for amendment by Entergy Operations, Inc. (the licensee), dated December 8, 2011, as supplemented by letters dated April 11, May 2, and September 5, 2012, and January 9 and March 8, 2013, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, as amended, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (Ii) that such activities will be conducted in compliance with the Commission's regulations; D. The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

Enclosure 1

- 2

2. Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment, and Paragraph 2.C.(2) of Facility Operating License No. NPF-47 is hereby amended to read as follows:

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 179 and the Environmental Protection Plan contained in Appendix B, are hereby incorporated in the license. EOI shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3. The license amendment is effective as of its date of issuance and shall be implemented within 90 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION Michael T. Markley, Chief Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Facility Operating License No. NPF-47 and Technical Specifications Date of Issuance: March 29, 2013

ATTACHMENT TO LICENSE AMENDMENT NO. 179 FACILITY OPERATING LICENSE NO. NPF-47 DOCKET NO. 50-458 Replace the following pages of the Facility Operating License No. NPF-47 and Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by Amendment number and contain marginal lines indicating the areas of change.

Facility Operating License Remove

-3 Technical Specifications Remove 3.3-73 3.3-73 3.3-74 3.3-74

-3 (3) EOI, pursuant to the Act and 10 CFR Part 70, to receive, possess and to use at any time special nuclear material as reactor fuel, in accordance with the limitations for storage and amounts required for reactor operation, as described in the Final Safety Analysis Report, as supplemented and amended; (4) EOI, pursuant to the Act and 10 CFR Parts 30,40 and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5) EOI. pursuant to the Act and 10 CFR Parts 30, 40 and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6) EOI, pursuant to the Act and 10 CFR Parts 30,40 and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C. This license shall be deemed to contain and is subject to the conditions specified in the Commission's regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1) Maximum Power Level EOI is authorized to operate the facility at reactor core power levels not in excess of 3091 megawatts thermal (100% rated power) in accordance with the conditions specified herein. The items identified in Attachment 1 to this license shall be completed as specified. Attachment 1 is hereby incorporated into this license.

(2) Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A, as revised through Amendment No. 179 and the Environmental Protection Plan contained in Appendix 8, are hereby incorporated in the license. EOI shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Amendment No. 179

LOP Instrumentation 3.3.8.1 SURVEILLANCE REQUIREMENTS

NOTES---------------------------------------------------------

1. Refer to Table 3.3.8.1-1 to determine which SRs apply for each LOP Function.
2. When a channel is placed in an inoperable status solely for performance of required Surveillances,"entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> provided the associated Function maintains DG initiation capability.

SURVEILLANCE FREQUENCY SR 3.3.8.1.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.8.1.2 Perform CHANNEL FUNCTIONAL TEST. 31 days SR 3.3.8.1.3 Perform CHANNEL CALIBRATION. 24 months SR 3.3.8.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. 24 months RIVER BEND 3.3-73 Amendment No. 81 168, 179

LOP Instrumentation 3.3.8.1 Table 3.3.8.1-1 (page 1 of 1)

Loss of Power Instrumentation REQUIRED CHANNELS PER SURVEILLANCE ALLOWABLE FUNCTION DIVISION REQUIREMENTS VALUE

1. Divisions 1 and 2 - 4.16 kV Emergency Bus Undervoltage
a. Loss of Voltage - 4.16 kV basis 3 SR 3.3.8.1.1 2. 3005 V and,; 3302 V SR 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4
b. Loss of Voltage - Time Delay SR 3.3.8.1.3 2. 2.67 seconds and SR 3.3.8.1.4 ,; 3.33 seconds
c. Degraded Voltage - 4.16 kV basis 3 SR 3.3.8.1.1 " 3689.0 V and,; 3735.2 V SR 3.3.81.2 SR 3.3.8.1.3 SR 3.3.8.1.4
d. Degraded Voltage - Time Delay. No SR 3.3.8.1.3 2. 46.59 seconds and LOCA SR 3.3.8.1.4 ,; 57.07 seconds
e. Degraded Voltage - Time Delay, SR 3.3.B.1.3 2. 4.5 seconds and LOCA SR 3.3.B.1.4 ,; 5.7 seconds
2. Division 3 - 4.16 kV Emergency Bus Undervoltage
a. Loss of Voltage - 4.16 kV basis 2 SR 3.3.B.1.1 " 3019 V and $ 3325 V SR 3.3.B.1.3 SR 3.3.8.1.4
b. Loss of Voltage Time Delay 2 SR 3.3.8.1.3 " 2.67 seconds and SR 3.3.B.1.4 s 3.33 seconds
c. Degraded Voltage - 4.16 kV basis 2 SR 3.3.8.1.1 " 3674.0 V and s 3721.2 V SR 3.3.6.1.2 SR 3.3.8.1.3 SR 3.3.6.1.4
d. Degraded Voltage - Time Delay, No 2 SR 3.3.8.1.3  ;;, 44.7 seconds and LOCA SR 3.3.8.1.4 ,; 54.62 seconds
e. Degraded Voltage - Time Delay, 2 SR 3.3.8.1.2 ,,4.5 seconds and LOCA SR 3.3.8.1.3 ,; 5.7 seconds SR 3.3.8.1.4 RIVER BEND 3,3-74 Amendment No. 8195128147151,179

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 179 TO FACILITY OPERATING LICENSE NO. NPF-47 ENTERGY OPERATIONS, INC.

RIVER BEND STATION, UNIT 1 DOCKET NO. 50-458

1.0 INTRODUCTION

By application dated December 8,2011 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML11349A246), as supplemented by letters dated April 11, May 2, and September 5,2012, and January 9 and March 8, 2013 (ADAMS Accession Nos.

ML12108A004, ML121250516, ML12255A169, ML13010A385, and ML13071A468, respectively), Entergy Operations, Inc. (Entergy, the licensee), requested changes to the Technical Specifications (TSs) for the River Bend Station, Unit 1 (RBS). The supplemental letters dated April 11, May 2, and September 5,2012, and January 9 and March 8,2013, provided additional information that clarified the application, did not expand the scope of the application as originally noticed, and did not change the U.S. Nuclear Regulatory Commission (NRC) staff's original proposed no significant hazards consideration determination as published in the Federal Register on April 17, 2012 (77 FR 22811).

In its license amendment request (LAR), the licensee proposed changes to: (1) extend the frequency of Surveillance Requirement (SR) 3.3.8.1.3 for calibration of loss of power instrumentation from 18 to 24 months with continued application of TS SR 3.0.2, which allows a 25 percent extension (i.e., grace period up to 30 months) to SR frequencies, and (2) add allowable value (AV) changes in TS Table 3.3.8.1-1, Loss of Power Instrumentation, which are necessary to address the discovery of non-conservative AVs in TS 3.3.8.1 (Amendment No. 168, dated August 31, 2010 (ADAMS Accession No. ML102350266>>.

2.0 REGULATORY EVALUATION

The NRC staff reviewed the proposed TS changes against the regulatory requirements and guidance listed in Sections 2.1 and 2.2 of this safety evaluation to ensure that there is reasonable assurance that the instrumentation systems and components affected by the proposed TS changes will perform their safety functions.

Enclosure 2

-2 2.1 Regulatory Reguirements Section 182a of the Atomic Energy Act requires applicants for nuclear power plant operating licenses to include TSs as part of the license. The NRC's regulatory requirements related to the content of the TSs are contained in Section 50.36, "Technical specifications," of Title 10 of the Code of Federal Regulations (10 CFR). The TS requirements in 10 CFR 50.36 include the following categories: (1) safety limits, limiting safety systems settings and control settings, (2) limiting conditions for operation (LCO), (3) surveillance requirements (SRs), (4) design features, (5) administrative controls, (6) decommissioning, (7) initial notification, and (8) written reports.

Specifically, 10 CFR 50.36 states, in part, that Each applicant for a license authorizing operation of a production or utilization facility shall include in his application proposed technical specifications in accordance with the requirements of this section.

In addition, 10 CFR 50.36(c)(3} states that 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 of operation will be met.

The regulations in 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities,"

establish the fundamental regulatory requirements. Specifically, Appendix A, "General Design Criteria for Nuclear Power Plants," to 10 CFR Part 50 provides criteria for the necessary design, fabrication, construction, testing, and performance requirements for structures, systems, and components important to safety.

The regulations in 10 CFR Part 50, Appendix A, General Design Criterion (GDC) 17, "Electric power systems," states, in part, that An onsite electric power system and an offsite electric power system shall be provided to permit functioning of structures, systems, and components important to safety. The safety function for each system (assuming the other system is not functioning) shall be to provide sufficient capacity and capability to assure that (1) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and (2) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents.

The loss of power diesel start instrumentation settings and control assures proper operation of safety-related loads as required by GDC 17 of 10 CFR Part 50, Appendix A The NRC staff reviewed the proposed TS changes against these requirements to ensure reasonable assurance that the systems affected by the proposed TS changes will perform their required safety functions.

~ 3 2.2 Regulatory Guidance The NRC staff considered the regulatory guidance provided in Generic Letter (GL) 91~04, "Changes in Technical Specification Surveillance Intervals to accommodate a 24-Month Fuel Cycle," dated April 2, 1991 (ADAMS Accession No. ML031140501). The licensee evaluated the proposed TS changes in accordance with the seven steps in Enclosure 2 of GL 91~04.

According to Enclosure 2 of GL 91-04, the licensee needs to address the following seven steps for calibration-related TS changes to provide an acceptable basis for increasing the calibration interval for instruments that are used to perform safety functions:

1. Confirm that instrument drift as determined by as-found and as-left calibration data from surveillance and maintenance records has not, except on rare occasions, exceeded acceptable limits for a calibration interval.
2. Confirm that the values of drift for each instrument type (make, model, and range) and application have been determined with a high probability and a high degree of confidence. Provide a summary of the methodology and assumptions used to determine the rate of instrument drift with time based upon historical plant calibration data.
3. Confirm that the magnitude of instrument drift has been determined with a high probability and a high degree of confidence for a bounding calibration interval of 30 months for each instrument type (make, model number, and range) and application that performs a safety function.

Provide a list of the channels by TS section that identifies these instrument applications.

4. Confirm that a comparison of the projected instrument drift errors has been made with the values of drift used in the setpoint analysis. If this results in revised setpoints to accommodate larger drift errors, provide proposed TS changes to update trip setpoints. If the drift errors result in a revised safety analysis to support existing setpoints, provide a summary of the updated analysis conclusions to confirm that safety limits and safety analysis assumptions are not exceeded.
5. Confirm that the projected instrument errors caused by drift are acceptable for the control of plant parameters to effect a safe shutdown with the associated instrumentation.
6. Confirm that all conditions and assumptions of the setpoint and safety analyses have been checked and are appropriately reflected in the acceptance criteria of plant surveillance procedures for channel checks, channel functional tests, and channel calibrations.

- 4

7. Provide a summary description of the program for monitoring and assessing the effects of increased calibration surveillance intervals on instrument drift and its effect on safety.

The NRC staff also considered the regulatory guidance provided in Regulatory Guide (RG) 1.105, Revision 3, "Setpoints for Safety-Related Instrumentation," December 1999 (ADAMS Accession No. ML993560062), which describes a method that the NRC staff considers acceptable for complying with the agency's regulations for ensuring that setpoints for safety related instrumentation have been determined with a high probability and a high degree of confidence to be within and remain within the TS limits.

RG 1.105 endorses Part I of Instrument Society of America (ISA) Standard 67.04-1994, "Setpoints for Nuclear Safety-Related Instrumentation," subject to NRC staff's clarifications, The staff used this guide to establish the adequacy of the licensee's setpoint calculation methodologies and the related plant surveillance procedures, In Regulatory Issue Summary (RIS) 2006-17, "NRC Staff Position on the Requirements of 10 CFR 50.36, Technical Specifications,' regarding Limiting Safety System Settings during Periodic Testing and Calibration of Instrument Channels," dated August 24,2006 (ADAMS Accession No. ML051810077), the NRC addresses requirements on limiting safety system settings that are assessed during the periodic testing and calibration of instrumentation.

RIS 2006-17 discusses issues that could occur during the testing of limiting safety system settings and that, therefore, may have an adverse effect on equipment operability, In NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," Branch Technical Position (BTP) 8-6, "Adequacy of Station Electric Distribution System Voltages," March 2007 (similar to the previous BTP PSB-1, July 1981) (ADAMS Accession No, ML070710478), states, in part, that The technical specifications should include limiting conditions for operations, surveillance requirements, trip setpoints, and maximum and minimum allowable values for the first level of undervoltage protection (LOOP [loss of offsite powerJ) relays and the second-level (degraded voltage) protection sensors and associated time delay devices,

3.0 TECHNICAL EVALUATION

3,1 Proposed TS Changes By letter dated December 8, 2011, the licensee requested the following changes: (1) extend the frequency of the SR 3,3.8,1.3 for calibration of loss of power instrumentation from 18 to 24 months with continued application of TS SR 3,0.2, which allows a 25 percent extension (Le, grace period up to 30 months) to SR frequencies, and (2) revise AVs in TS Table 3,3.8,1-1, "Loss of Power Instrumentation."

- 5 3.1.1 Changes to Frequency of SR 3.3.8.1.3 Current SR 3.3.8.1.3 states a frequency of "18 months."

Revised SR 3.3.8.1.3 would state a frequency of "24 months."

3.1.2 Changes to Allowable Values in TS Table 3.3.8.1-1 Current TS Table 3.3.8.1-1, Function 1.a AV states:

~ 2850 V and ~ 3090 V Revised TS Table 3.3.8.1-1, Function 1.a AV would state:

~ 3005 V and ~ 3302 V Current TS Table 3.3.8.1-1, Function 1.d AV states:

~ 53.4 seconds and ~ 66.6 seconds Revised TS Table 3.3.8.1-1, Function 1.d AV would state:

~ 46.59 seconds and ~ 57.07 seconds Current TS Table 3.3.8.1-1, Function 2.a AV states:

~ 2831 V and ~ 3259 V Revised TS Table 3.3.8.1-1, Function 2.a AV would state:

3019 V and ~ 3325 V Current TS Table 3.3.8.1-1, Function 2.d AV states:

~ 53.4 seconds and ~ 66.6 seconds Revised TS Table 3.3.8.1-1, Function 2.d AV would state

~ 44.7 seconds and ~ 54.82 seconds By letter dated December 8, 2011, the licensee requested that a footnote be added to TS Table 3.3.8.1-1 and referenced in the AVs for Functions 1.a, 1.d, 2.a, and 2.d, which would state:

(Note 1 - These values become effective as of the end of RF17.)

By letter dated March 8, 2013, the licensee withdrew its request to add Note 1 and reference it in TS Table 3.3.8.1-1.

- 6 3.2 Evaluation of the Revised Allowable Values The RBS Updated Safety Analysis Report (USAR) Section 8.3.1.1.3.9, "Adequacy of Electrical Distribution System Voltages," states that:

The first undervoltage scheme detects loss of power at the Class 1E buses. This undervoltage setpoint is set below any anticipated transient voltage condition, with a time delay of approximately 3 seconds.

The second level of undervoltage protection is set at approximately 90 percent and utilizes two separate time delays based on the following conditions:

1. The first time delay is approximately 5 sec, which establishes a sustained degraded voltage condition (Le., something longer than a motor starting transient). Following this delay, an alarm in the main control room alerts the operator to the degraded condition. The subsequent occurrence of a LOCA [Ioss-of-coolant accident] signal immediately separates the Class 1E distribution system from the offsite power system, starts load shed logic and load sequence timers, starts the diesel generator, and permits auto-close of the diesel generator breaker.
2. The second time delay is approximately 60 sec, which ensures that permanently connected Class 1E loads will not be damaged. Following this time delay, if the operator has failed to restore adequate voltages, the Class 1E system is automatically separated from the offsite power system, the load shed logic and load sequence timers start, and the diesel generator starts and permits auto-close of the diesel generator breaker.

Two completely separate schemes of undervoltage protection with similar settings are provided on the Division III Class 1E HPCS [high-pressure core spray] bus at the 4.16-kV level.

In the LAR, the licensee stated that the RBS TS Bases criteria for the degraded voltage instrumentation requires that (1) the degraded voltage AVs be low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient voltage is available to the required equipment, and (2) the time delay AVs be long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment. The licensee also stated that it identified a group 1

of motor-operated valves under the Generic Letter (GL) 89-10 program to have insufficient voltage to pick up their torque switch, allowing potential failure after reaching their safety position. Thus, although the valves maintain their operability, full functionality was not maintained under existing analysis. To bring the valves back to full functionality, RBS has modified the offsite power requirements to ensure that grid voltage is no lower than 97.5 percent, up from the current limit of 95 percent. This change resulted in an increase in U.S. Nuclear Regulatory Commission, "Safety-Related (1) Motor-Operated Valve Testing and Surveillance Results of the Public Workshops (GL 89-10) - 10 CFR 50.54(f)," dated June 28, 1989 (ADAMS Accession No. ML031150300).

minimum grid voltage operability limit from 95 percent to 97.5 percent. The setpoint for the "low grid voltage" alarm in the main control room was changed from 98 percent to 98.2 percent.

To allow additional operating margin, the LAR proposes changes to the TS Table 3.3.8.1-1, "Loss of Power Instrumentation," AVs for the following functions:

  • Function 1.a, Divisions 1 and 2 - 4.16 kV Emergency Bus Undervoltage, Loss of Voltage- 4.16 kV Basis
  • Function 1.d, Divisions 1 and 2 - 4.16 kV Emergency Bus Undervoltage, Degraded Voltage - Time Delay, No LOCA
  • Function 2.a, Division 3 - 4.16 kV Emergency Bus Undervoltage, Loss of Voltage - 4.16 kV Basis
  • Function 2.d, Division 3- 4.16 kV Emergency Bus Undervoltage, Degraded Voltage - Time Delay, No LOCA Specifically, the following tables show the new revised TS AV limits:

Divisions 1 and 2 Function Existing AVs Revised AVs 1.a ~ 2850 V and s 3090 V ~ 3005 V and s 3302 V 1.d ~ 53.4 seconds and s ~ 46.59 seconds and s 66.6 seconds 57.07 seconds Division 3 Function Existing AVs Revised AVs I 2.a ~ 2831 V and S 3259 V ~ 3019 V and S 3325 V I 2.d I~ 53.4 seconds and S ~ 44.7 seconds and S 66.6 seconds 54.82 seconds \

The NRC staff reviewed the proposed changes and the licensee's justification for the change.

The NRC staff requested additional information (RAI) by letter dated March 12,2012 (ADAMS Accession No. ML120720409), regarding the licensee's calculation to demonstrate that all Class 1E motors have adequate starting and running voltages, based on the setpoint values specified in TS Table 3.3.8.1, rather than higher voltage shown on the grid stability study. By letter dated April 11, 2012, the licensee stated that its calculation demonstrated that all Class 1E motors have adequate starting and running voltages based on the proposed setpoint values specified in TS Table 3.3.8.1. The licensee's calculation used the lower analytical limit, which is more conservative than the setpoint AVs, to demonstrate that all equipment has sufficient voltage to meet operating requirements and none of the protective devices actuate at the lower analytical limit within the proposed time delays. The licensee stated that because all Class 1E motors were purchased to be capable of starting and accelerating their driven equipment with

-8 motor terminal voltages of 70 or 80 percent of motor nameplate voltage without affecting performance or equipment life, no operability concerns exist for any equipment. The NRC staff requested the licensee clarify how it ensures that plant modifications and replacement equipment installed since the original plant construction have maintained 70 or 80 percent minimum voltage operating requirements for the motors. In response, the licensee stated that all plant modifications and replacement equipment are controlled in accordance with requirements specified in the equipment design specifications and plant calculations which will ensure that the correct voltage requirements are specified for the equipment that is being replaced. Based on the above, the NRC staff determined that the licensee has adequate controls in place to maintain the design basis requirements throughout the life of the plant.

The NRC staff's review concluded that the proposed AVs are more conservative than the existing AVs to ensure that the Class 1E distribution system remains connected to the offsite power system when adequate offsite voltage is available and motor starting transients are considered. The proposed time delay continues to provide equipment protection while preventing a premature separation from offsite power. The change in the degraded voltage protection voltage and time delay allowable values allows the protection scheme to function as originally designed. Calculations have also demonstrated that adequate margin is present to support the decrease in the minimum allowable Division 3 degraded voltage. During a postulated degraded voltage condition, the degraded voltage time delays will continue to isolate the Class 1E distribution system from offsite power before the diesel is ready to assume the emergency loads. Therefore, the AV changes continue to meet the accident analysis assumptions.

The proposed LAR was evaluated by the NRC staff to determine whether applicable regulations and requirements continue to be met. It was determined that the proposed changes do not require any exemptions or relief from regulatory requirements, other than the TSs. Applicable regulatory requirements will continue to be met, adequate defense-in-depth will be maintained, and sufficient safety margins will be maintained. Based on the above, the NRC staff concludes that the proposed changes to the AVs will not impact the licensee's compliance to the regulatory requirements of 10 CFR 50.36(c) and GDC 17 and, therefore, the proposed changes to the AVs are acceptable.

3.3 Evaluation of 18- to 24-Month Instrumentation Calibration By letter dated August 10, 2009 (ADAMS Accession No. ML092470152), the licensee submitted LAR 2009-05 to extend the plant fuel cycle from 18 months to 24 months. The NRC approved this LAR by Amendment No. 168 dated August 31, 2010 (ADAMS Accession No. ML102350266).

In this LAR, the licensee proposed several TS changes in accordance with the guidelines provided in the NRC Generic Letter (GL) 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991.

In GL 91-04, the NRC identified seven steps for licensees to address for the evaluation of 24-month instrumentation calibration extension. In Attachment 1 of the LAR dated December 8, 2011, the licensee addressed those seven steps. To comply with these seven steps, the licensee performed historical drift evaluation in accordance with the guidelines provided in Electric Power Research Institute (EPRI) Technical Report TR-103335-R1, "Guidelines for Instrument Calibration Extension/Reduction Statistical Analysis of Instrument Calibration Data,

- 9 Final Report," dated October 1998. Entergy stated that the setpoint calculations and affected calibration and functional test procedures have been or will be revised prior to implementation to reflect the new 30-month drift values. The revised setpoint calculations were developed in accordance with the RSS commitment to the guidance provided in RG 1.105 as implemented by the RSS setpoint methodology. These calculations determined the instrument uncertainties, setpoints, and AVs for the affected function. The AVs were determined in a manner suitable to establish limits for their application. As such, the AVs ensure that sufficient margins are maintained in the applicable safety analyses to confirm the affected instruments are capable of performing their intended design function. The licensee provided the details of these evaluations in Attachment 3 of the lAR dated December 8, 2011. In these evaluations, the licensee used channel calibration data for associated instruments for at least five operating cycles including the spring 2011 refueling cycle. The time equivalent of five cycles of 18 months history data is equal to three cycles of 30 months history.

The maximum drift for a 30-month calibration interval for each calculation is summarized in the table below:

Relay 30 Month Drift ASS ITE-27H Undervoltag 0.392 VAC*

G13.18.6.3-009 ASS ITE-62 Timers 2.072% Setpoint G13.18.6.3-012 GE NG 5.823 VAC G13.18.6.3-014 3.725% Setpoint

  • Volts alternating current The above four calculations show that the instrument drift was determined from the as-found and as-left calibration data and addresses the criteria in Gl 91-04, Step 1. The licensee used these calculated drift values as as-found tolerances (AFT) for the above-specified devices. The NRC staff considers this approach conservative because the accepted industry practice calculates the AFT as the square-root-of-the-sum-of-the-squares (SRSS) of the as-left tolerance (AlT), measurement and test equipment (M& TE) tolerance, and drift (DR).

In addition in addressing Gl 91-04, Step 1, the licensee stated in the LAR that TS AVs were exceeded twice based on the failure history evaluation and the drift study. Sased on the time period covered and the number of instruments included in the study, the NRC staff concludes that, except on rare occasions, the instrument drift has not exceeded acceptable limits for a calibration interval. In Attachment 3 of the LAR dated December 8,2011, the licensee provided the following summary of the two events:

On September 19, 1997, a timer relay associated with SR 3.3.8.1.3, Functions 1.c, 1.d, and 1.e, had contacts that did not change state when the timer timed out. The relay was replaced with an ASS Model ITE-62K relay and tested satisfactorily. The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism. On October 31,2004, a timer relay associated with SR 3.3.8.1.3, Functions 1.e, failed its time delay criteria. The relay's time delay could not be adjusted within the acceptable range. The relay was replaced with an ASS ModeIITE-27N relay and tested satisfactorily. Subsequent evaluation concluded the relay time delay

- 10 was off in the conservative direction, and therefore, the protection scheme was more subject to false actuation. It would have operated to perform its protective function. The identified failure is unique and does not occur on a repetitive basis and is not associated with a time-based failure mechanism.

The licensee also stated there were two failures identified over the review period related to ASEA Brown Boveri relays. One failure was related to a Model ITE-62K relay and the other failure, a ModeIITE-27H relay. In both cases, the defective relays were replaced. Both failures were in the 4.16 kV Emergency Bus Undervoltage/Degraded Voltage function of the Loss of Power Instrumentation. The licensee observed no time-based mechanisms in these failures and concluded that based on the history of system performance, the impact of this change on safety, if any, was small. Based on the above, the NRC staff agreed with this conclusion.

The drift calculations described above determined the standard deviation of the drift distribution for each type of component to meet the criteria in GL 91-04, Step 2. This distribution was confirmed to be approximately normal and hence, the standard deviation was weighted, based on sample size, so that the determined drift for a 30-month interval was known with high probability and high confidence level (I.e., 95/95).

In response to the NRC staff's RAI dated December 5, 2012 (ADAMS Accession No. ML12341A003), bye-mail dated January 17, 2013, the licensee provided the following drift study calculations (ADAMS Package Accession No. ML13018A081):

1. G13.18.6.3-006, EC#11753, Rev. 0, Drift Study for ABB ModeIITE-27H Undervoltage Relays (ADAMS Accession No. ML13018A100).
2. G13.18.6.3-009, EC#11753, Rev. 0, Drift Study for ABB Mode11TE-62 Timers (ADAMS Accession No. ML13018A103).
3. G13.18.6.3-012, EC#11753, Rev. 0, Drift Study for General Electric Model NGV13B Undervoltage Relays (ADAMS Accession No. ML13018A107).
4. G13.18.6.3-014, EC#11753, Rev. 0, Drift Study for Agastat ETR Series Time Delay Relays (ADAMS Accession No. ML13018A110).

In these calculations, the licensee calculated the drift values by subtracting the previous as-left setting from the subsequent as-found setting. The licensee performed t-Tests on these drift values and limited the maximum number of outliers to one. In response to NRC staff's RAI dated August 7,2012 (ADAMS Accession No. ML12220A546), by letter dated September 5, 2012, the licensee stated the sample sizes for the drift calculations are as summarized below:

Calculation Sample Size G13.18.6.3-006 41 G13.18.6.3-009 42 G13.18.6.3-012 58 G13.18.6.3-014 48

- 11 Previous NRC staff evaluations of 24-month fuel cycle extensions have found that minimum sample sets of 30 samples provided statistically significant results. The NRC staff reviewed the sample sizes for the above calculation and concluded that they met the criteria. To ensure the drift data is based on a normal distribution, W or D-Prime tests may be performed. The test to be performed is dependent on the sample size. The licensee used W test for a final data set (FDS) (i.e., without outlier) with less than 50 samples and D-Prime test for an FDS greater than 50 samples. Calculation G13.8.6.3-012 used 58 samples. The licensee calculated aD-Prime value of 123.7 which is within the acceptable range of 119.9 and 126.5 for 58 data points. In the remaining three calculations, the licensee performed the W test. Based on the results of each of the four calculations, the licensee observed the random portion of drift is moderately time dependent with negligible bias. The licensee did not observe any strong time dependency. The NRC staff compared the tolerance interval factors used in these calculations against the degree of freedom specified in the NUREG/CR-3659, "A Mathematical Model for Assessing the Uncertainties of Instrumentation Measurements for Power and Flow of PWR Reactors,"

February 1985 (ADAMS Accession No. ML081550335), and concluded that the final drift parameters meet the needs for assessing this interval at the 95/95 confidence level, and addresses the criteria in GL 91-04, Step 3.

In response to an NRC staff RAI, bye-mail dated October 16, 2012 (ADAMS Accession No. ML12291A763), the licensee submitted the following calculations in support of ALT, AFT, Loop Uncertainty (LU), Total Loop Uncertainty (TLU), Nominal Trip Setpoint (NTSP), and AVs:

1. Calculation G13.18.3.1-004, EC#40339, Rev. 0, Degraded Voltage Relay Setpoints for ENS-SWG01A and ENS-SWG01 B
2. Calculation G13.18.3.1-005, EC#40339, Rev. 0, Degraded Voltage Relay Setpoints for E22-S004
3. Calculation G13.18.6.2-ENS*002, EC#40339, Rev. 3, Instrument Loop Uncertainty Setpoint Determination for ABB Model 27H Undervoltage Relay
4. Calculation G13.18.6.2-ENS*004, EC#40339, Rev. 2, Loop Uncertainty Determination for DIV III Loss of Voltage Relays - GE Model NVG Undervoltage Relay
5. Calculation G13.18.6.2-ENS*006, EC#40339, Rev. 2, Loop Uncertainty Determination for Div I and II Under Voltage Time Delay Relays - ABB Model 62K and 62L Time Delay Relays
6. Calculation G13.18.6.2-ENS*007, EC#40339, Rev. 2, Loop Uncertainty Determination for Div III Under Voltage Time Delay Relays - Agastat ETR14 Time Delay Relay The above calculations demonstrate that the drift was conservatively incorporated into the loop uncertainty calculations and hence, demonstrate that the analyses meet the criteria in GL 91-04, Steps 4 and 5.

- 12 In addition, in the above six documents, the licensee calculated the NTSP from the Analytical Limit (AL) by subtracting or adding TLU from AL and AV from AL by subtracting or adding LU from AL. TLU is calculated from LU by adding loop drifts. The NRC staff concludes that in calculating the LU, the licensee has been conservative. The staff noted one exception for Agastat ETR14 Time Delay Relay, where the vendor specified a reference accuracy of

+ 5 percent including temperature and power supply variation effects, but in Calculation G13.18.6.2-ENS*007, EC#40339, Rev. 2, Loop Uncertainty Determination for Agastat ETR14 Time Delay Relay, the licensee calculated the device uncertainty as SRSS of reference accuracy, temperature, and power supply. Thus, for example, for 62S3 and 62S4 relays with relay setting of 3 seconds, the licensee calculated the device uncertainty as 0.258 seconds while the vendor-provided reference accuracy is only 0.15 seconds.

In the setpoint drift study, Calculation G13.18.6.3-014, Rev. 0 (ADAMS Accession No. ML13018A110), the licensee calculated the drift for Agastat ETR Series Time Delay Relays to be 3.725 percent of the setpoint for up to 915 days. Based on this data and with relay setting of 45.24 seconds, the licensee calculated the AFT to be + 0.03725 x 45.24 = + 1.685 seconds; see Calculation G13.18.6.2-ENS*007, EC#40339, Rev. 2 (ADAMS Accession No. ML12125A312). The vendor's catalogue, VTD-A348-0111, for this device (ADAMS Accession No. ML13022A224), indicates the reference accuracy for this Time Delay Relay to be

+ 5 percent of the relay time delay setting which equals 45.24 x 0.05 = 2.62 seconds. It is the licensee's normal practice to calculate the ALT tolerance as the SRSS of the reference accuracy, the M&TE accuracy, and readability. For this particular relay, the calculated ALT of 2.62 seconds is much larger than the AFT of 1.685 seconds calculated from the setpoint drift evaluation in Calculation G13.18.6.3-014, Rev. O. The licensee selected the ALT to be 80 percent of the AFT or 1.35 seconds. By letter dated January 9, 2013, in response to an NRC staff RAI, the licensee stated, in part, that To select an as-left value, the historical calibration data (which accounts for device accuracy, M&TE accuracy, and readability) was reviewed and a value of 80% of the AFT was selected as the As-Left tolerance. This value was readily achievable during the calibration process and provided sufficient margin to allow for detection of instrument or channel degradation.

Because this ALT is based on plant setting data, the NRC staff concludes this selection is acceptable for addressing the criteria in GL 91-04, Steps 4 and 5.

It is generally assumed in the setpoint and safety analysis calculations that the values for device accuracy, M&TE accuracy, readability, and drift do not change over time. In order to periodically confirm this assumption, the calibration procedures include AL T and AFT.

Therefore, in order to address the criteria in GL 91-04, Step 6, the licensee calculated the ALT and AFT, and will incorporate these values in the appropriate plant procedure as described below:

1. Using similar setpoint calculation methodology for ABB Model 62K and 62L Time Delay Relays, the licensee performed Calculation G13.18.6.2-ENS*006, EC#40339, Rev. 2, and calculated the M&TE accuracy to be:t. 4.15 x 10-3 seconds and the vendor provided reference accuracy to be 0.505 seconds.

Based on these results, the licensee calculated the ALT to be:t. 0.51 seconds.

- 13 The licensee used drift study, Calculation G13.18.6.3-009, EC#11753, Rev. 0, to calculate the 30-month drift and used this drift value (:!:. 1.05 seconds) as the AFT in Calculation G 13.18.6.2-ENS*006, EC#40339, Rev. 2. In this case, the AFT is about twice the value of AL T.

2. Similarly, in Calculation G13.18.6.2-ENS*004, EC#40339, Rev. 2, for GE Model NGV relays, the licensee calculated the ALT to be:!:. 0.99 VAC based on the vendor-provided reference accuracy. The licensee determined the AFT to be
!:. 5.82 VAC based on a plant-specific drift evaluation. Therefore, the ALT is much smaller than the loop drift and AFT.
3. Similarly, in Calculation G 13.18.6.2-ENS*002, EC#40339, Rev. 3, for GE Model NGV relays, the licensee calculated the AL T to be:!:. 0.21 VAC based on vendor provided reference accuracy and determined the AFT to be:!:. 0.392 VAC based on a plant-specific drift evaluation. Therefore, the AL T is much smaller than the loop drift and AFT.

For addressing the criteria in GL 91-04. Step 6, by letter dated January 9,2013, in response to an NRC staff RAI. the licensee provided a markup copy of the current surveillance procedure and committed to perform the following corrective actions based on AFT values:

a. Calibration as-found value within the ALT minimum and maximum: no action is required, as-found equal to as-left and surveillance is complete.
b. Calibration as-found value outside ALT minimum and maximum but within AFT minimum and maximum: calibrate the relay to within AL T minimum and maximum, and surveillance is complete.
c. Calibration as-found value outside AFT minimum and maximum but within Technical Specification Allowable Values: calibrate relay to within AL T minimum and maximum. Evaluate relay to verify that it is functioning as expected and would be expected to pass the next surveillance test.

Initiate a Condition Report for engineering evaluation of component future operation. Surveillance is complete.

d. Calibration as-found value outside Technical Specification Allowable Values: channel is inoperable and required Technical SpeCification actions are taken.
e. If the relay as-left value cannot be returned to within AL T, then the device will be declared inoperable.

- 14 In addition, for conformance with Technical Specifications Task Force (TSTF) Traveler TSTF-493, Revision 4, "Clarify Application of Setpoint Methodology for LSSS Functions," dated January 5,2010 (ADAMS Accession No. ML100060064), and the associated errata,

'Transmittal of TSTF-493, Revision 4, Errata," dated April 23, 2010 (ADAMS Accession No. ML101160026), the licensee has added the following sentence to the TS Bases for SR 3.3.5.3:

There is a plant-specific program which verifies that the instrument channel functions as required by verifying the As-Left and As-Found settings are consistent with those established by the setpoint methodology.

With the change to the TS Bases 3.3.5.3 and the commitment to the above statements regarding corrective actions to ensure the plant procedures are consistent with GL 91-04, Step 6, the NRC staff concludes that the proposed TS changes comply with TSTF-493 requirements and hence, comply with RIS 2006-17 recommendations.

To meet the criteria in GL 91-04, Step 7, in the LAR dated December 8, 2011, the licensee provided the details of the program for monitoring and assessing the effects of the increased calibration surveillance intervals on instrument drift and its effect on safety. The licensee stated that the instruments with TS calibration surveillance frequencies extended to 24 months will be monitored and trended in accordance with the trending program described in Section 3.2 of of the LAR The as-found and as-left calibration data will be recorded for each 24-month calibration activity for a period of three cycles. This will identify occurrences of instruments found outside of their AV and instruments whose performance does not comply with the assumptions in the drift or setpoint analysis. When as-found conditions are outside the AV, an evaluation will be performed in accordance with the RBS corrective action program to determine if the assumptions made to extend the calibration frequency are still valid and to evaluate the effect on plant safety.

The NRC has approved license amendments extending SRs to accommodate a 24-month fuel cycle for (1) Browns Ferry Nuclear Plant, Units 1, 2, and 3, dated September 28, 2006, (2)

Clinton Power Station Unit 1 dated October 21, 2005, (3) Monticello Nuclear Generating Plant dated September 30,2005, (4) RBS dated August 31,2010, and (5) Oconee Nuclear Station, Units 1, 2, and 3, dated April 20, 2012 (ADAMS Accession Nos. ML062170002, ML052940480, ML052780367, ML102350266, and ML12086A289, respectively).

Based on the above, the NRC staff concludes that the licensee performed the plant instrument drift data evaluation consistent with the seven steps outlined in GL 91-04 for a 24-month fuel cycle, performed the setpoint calculations in conformance with RG 1.105, established plant procedures to monitor and evaluate the instrument data for the next three refueling cycles and implemented corrective measures, as necessary. Furthermore, the NRC staff has approved similar TS changes for this plant and many other nuclear plants. Based on the above, the NRC staff concludes that the proposed TS changes conform to the guidance provided in GL 91-04, RG 1.105, RIS 2006-17, and TSTF-493, Revision 4, and are, therefore, acceptable.

- 15

3.4 CONCLUSION

The NRC staff evaluated the licensee's justifications for the proposed TS changes specified in Section 3.1 of this safety evaluation. The NRC staff concludes that the licensee performed the setpoint calculations on NTSP and AL T and AFT in conformance with the requirements of RG 1.105. In addition, the licensee performed drift evaluations of the instruments subject to the LAR and the NRC staff concludes the evaluations met the criteria of RG 91-04. Furthermore, the licensee has initiated plant procedures to comply with TSTF-493, Revision 4, and RIS 2006-17. The NRC staff concludes that the proposed TS changes to TS 3.3.8.1 and TS Table 3.3.8.1.1-1 comply with the requirements of 10 CFR 50.36 and GDC 17. Therefore, the proposed TS changes are acceptable.

4.0 REGULATORY COMMITMENTS In an LAR dated August 10, 2009, and approved by the NRC staff on August 31,2010, the licensee made the following regulatory commitment, which is applicable to this amendment:

Instruments with ts calibration surveillance frequencies extended to 24 months will be monitored and trended. As-found and as-left calibration data will be recorded for each 24 month calibration activity for a period of three cycles.

By letter dated December 8, 2011, Entergy made the following regulatory commitment:

RBS setpoint calculations and affected calibration and functional test procedures, have been revised, or will be revised prior to implementation to reflect the new 30-month drift values.

The NRC staff concludes that reasonable controls for the implementation and for the subsequent evaluation of the proposed changes pertaining to the above regulatory commitment is best provided by the licensee's administrative processes, including its commitment management program. The regulatory commitment above does not warrant the creation of regulatory requirements (items requiring prior NRC approval of subsequent changes).

5.0 STATE CONSULTATION

In accordance with the Commission's regulations, the Louisiana State official was notified of the proposed issuance of the amendment. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding published in the Federal Register on April 17, 2012 (77 FR 22811). Accordingly, the

- 16 amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9).

Pursuant to 10 CFR 51.22{b), no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

7.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) there is reasonable assurance that such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

S.O REFERENCES

1. Roberts, J. C., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "License Amendment Request 2011-05, Degraded Voltage Surveillance Frequency Extension and Allowable Value Changes, River Bend Station - Unit 1," dated DecemberS, 2011; includes Calculation G13.1S.3.6*016, EC#31715, Rev. 2, Degraded Voltage Calculations for Class 1E Buses and 4S0V Motor Operated Valves (ADAMS Accession No. ML11349A246).
2. Roberts, J. C., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information on License Amendment Request 2011-05, River Bend Station - Unit 1," dated April 11, 2012 (ADAMS Accession No. ML 1210SA004).
3. Goodman, H. A., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information on License Amendment Request 2011-05, River Bend Station - Unit 1," dated May 2, 2012 (ADAMS Accession No. ML121250516). This letter transmitted the following calculations also sent via electronic mail from D. H. Williamson, Entergy Operations, Inc., to Alan Wang, U.S. Nuclear Regulatory Commission, dated January 31,2012 (ADAMS Accession No. ML12261A491):
a. Calculation G13.1S.3.1-004, Rev. 0, Degraded Voltage Relay Setpoints for ENS-SWG01A and ENS-SWG01B (ADAMS Accession No. ML12125A307).
b. Calculation G13.1S.3.1-005, Rev. 0, Degraded Voltage Relay Setpoints for E22-S004 (ADAMS Accession No. ML 12125A30S).
c. Calculation G13.1S.6.2-ENS*002, EC#27437, Rev. 2, Instrument Loop Uncertainty Setpoint Determination for ABB Model 27H Undervoltage Relay (ADAMS Accession No. ML12125A309).
d. Calculation G13.1S.6.2-ENS*004, EC#27437, Rev. 1, Loop Uncertainty Determination for DIV III Loss of Voltage Relays - GE Model NGV Undervoltage Relay{ADAMS Accession No. ML 112125A310).

- 17

e. Calculation G13.1B.6.2-ENS*006, EC#27437, Rev. 1, Loop Uncertainty Determination for Div I and II Under Voltage Time Delay Relays - ABB Model 62K and 62L Time Delay Relays, (ADAMS Accession No. ML12125A311).
1. Calculation G13.1B.6.2-ENS*007, EC#27437, Rev. 1, Loop Uncertainty Determination for Div III Under Voltage Time Delay Relays - Agastat ETR14 Time Delay Relay (ADAMS Accession No. ML12125A312).
4. Roberts, J. C., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information on License Amendment Request 2011-05, River Bend Station - Unit 1," dated September 5,2012 (ADAMS Accession No. ML12255A169).
5. Roberts, J. C., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Response to Request for Additional Information on License Amendment Request 2011-05, River Bend Station - Unit 1," dated January 9,2013 (ADAMS Accession No. ML 13010A3B5).
6. Roberts, J. C., Entergy Operations, Inc., letter to U.S. Nuclear Regulatory Commission, "Supplement to License Amendment Request 2011-05, River Bend Station - Unit 1,"

dated March B, 2013 (ADAMS Accession No. ML 13071A46B).

7. Williamson, D. H., Entergy Operations, Inc., electronic mail to Alan Wang, U.S. Nuclear Regulatory Commission, dated October 16, 2012 (ADAMS Accession No. ML12291A763). This email transmitted the following calculations:
a. Calculation G13.1B.6.2-ENS*002, EC#27437, Rev. 3, Instrument Loop Uncertainty Setpoint Determination for ABB Model27H Undervoltage Relay.
b. Calculation G13.1B.6.2-ENS*004, EC#27437, Rev. 2, Loop Uncertainty Determination for DIV III Loss of Voltage Relays - GE Model NGV Undervoltage Relay.
c. Calculation G13.1B.6.2-ENS*006, EC#27437, Rev. 2, Loop Uncertainty Determination for Div I and 1/ Under Voltage Time Delay Relays - ABB Model 62K and 62L Time Delay Relays.
d. Calculation G13.1B.6.2-ENS*007, EC#27437, Rev. 2, Loop Uncertainty Determination for Div III Under Voltage Time Delay Relays - Agastat ETR14 Time Delay Relay.
e. Calculation G13.1B.6.2-ENS*002, ED#40339, Rev. 3, Instrument Loop Uncertainty/Setpoint Determination for the ABB Model27H Undervoltage Relay.
1. Calculation G13.1B.3.1-005, Rev. 0, Degraded Voltage Relay Setpoints for E22-S004 .(ADAMS Accession No. ML 12125A30B).

- 18

g. "White paper" which discusses the methodology used in this revision.
8. Williamson, D. H., Entergy Operations, Inc., electronic mail (3) to Alan Wang, U.S.

Nuclear Regulatory Commission, dated November 7,2012, transmitting the following vendor manuals (ADAMS Accession Nos. ML13022A213, ML13022A137, and ML13022A184):

a. Brown Boveri ITE Solid-State Timing Relays (ADAMS Accession Nos.

ML13022A138 and ML13022A144).

b. Amerace Electronic - Agastat Relays (ADAMS Accession Nos. ML13022A220 and ML13022A224).
c. Brown Boveri Undervoltage and Overvoltage ITE-27 and ITE-59 Relays (ADAMS Accession Nos. ML13022A192 and ML13022A195).

Principal Contributors: R. Mathew S. Mazumdar Date: March 29, 2013

March 29,2013 Vice President, Operations Entergy Operations, Inc.

River Bend Station 5485 US Highway 61 N St. Francisville, LA 70775

SUBJECT:

RIVER BEND STATION, UNIT 1 -ISSUANCE OF AMENDMENT RE:

DEGRADED VOLTAGE SURVEILLANCE FREQUENCY EXTENSION AND ALLOWABLE VALUE CHANGES (TAC NO. ME7767)

Dear Sir or Madam:

The Commission has issued the enclosed Amendment No. 179 to Facility Operating License No. NPF-47 for the River Bend Station, Unit 1. The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated December 8, 2011, as supplemented by letters dated April 11, May 2, and September 5, 2012, and January 9 and March 8,2013.

The amendment revises Surveillance Requirement (SR) 3.3.8.1.3 for calibration of loss of power instrumentation to extend the frequency of the SR from 18 to 24 months, and revises certain allowable values in TS 3.3.8.1, "Loss of Power Instrumentation."

A copy of our related Safety Evaluation is enclosed. The Notice of Issuance will be included in the Commission's next biweekly Federal Register notice.

Sincerely, I RAJ Alan B. Wang, Project Manager Plant Licensing Branch IV Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-458

Enclosures:

1. Amendment No. 179 to NPF-47
2. Safety Evaluation cc w/encls: Distribution via Listserv DISTRIBUTION:

PUBLIC RidsNrrDorlDpr Resource RidsOgcRp Resource LPLIV rlf RidsNrrDorlLpl4 Resource RidsRgn4MailCenter Resource RidsAcrsAcnw_MailCTR Resource RidsNrrDssStsb Resource SMazumdar, NRRlDE/EICB RidsNrrDeEeeb Resource RidsNrrLAJBurkhardt Resource RMathew, NRRlDE/EEEB RidsNrrDeEicb Resource RidsNrrPMRiverBend Resource ADAMS Accession No ML13060A210 *SE memo dated OFFICE NRR/DORULPL4/PM NRRIDORULPL4/LA NRR/DSS/STSB/BC NRR/DElEEEB/BC NAME ABWang JBurkhardt RElliott JAndersen*

~/13 3/8/13 3/13/13 5nt12 OFFICE R/DE/EICB/BC OGC NLO NRR/DORULPL4/BC NRR/DORULPL4/PM ABWang (JPolickoski NAME JThorp* LSubin MMarkley (CFLyon for)

  • for) i DATE 2/19/13 3/15/13 3/22/13 3/29/13 OFFICIAL AGENCY RECORD
Retrieved from "https://kanterella.com/w/index.php?title=ML13060A210&oldid=2458029"