RBG-47193, License Amendment Request 2011-05 Degraded Voltage Surveillance Frequency Extension and Allowable Value Changes

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License Amendment Request 2011-05 Degraded Voltage Surveillance Frequency Extension and Allowable Value Changes
ML11349A246
Person / Time
Site: River Bend Entergy icon.png
Issue date: 12/08/2011
From: Roberts J
Entergy Operations
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
LAR 11-005, RBG-47193
Download: ML11349A246 (44)
v • d • e


Text

Entergy Operations, Inc.

River Bend Station 5485 U. S. Highway 61 N SEntergy St. Francisville, LA 70775 Tel 225 381 4149 Fax 225 635 5068 jrober3@entergy.com Jerry C. Roberts Director, Nuclear Safety Assurance RBG-47193 December 8, 2011 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

SUBJECT:

License Amendment Request 2011-05 Degraded Voltage Surveillance Frequency Extension and Allowable Value Changes River Bend Station - Unit 1 Docket No. 50-458 License No. NPF-47

REFERENCES:

(1) Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle,"

dated April 2, 1991 (2) License Amendment Request 2009-05, 24-Month Fuel Cycles, August 10, 2009 RBF1-11-0145

Dear Sir or Madam:

Pursuant to 10 CFR 50.90, Entergy Operations, Inc. hereby requests an amendment to Appendix A, Technical Specifications (TS), of Facility Operating License No. NPF-47 for River Bend Station - Unit 1 (RBS). This amendment will, (1) extend the frequency of Surveillance Requirement (SR) 3.3.8.1.3 (calibration of loss of power instrumentation) from 18 to 24 months, and, (2) revise certain Allowable Values in TS 3.3.8.1, "Loss of Power Instrumentation." The SR extension will make the administration and performance of that SR consistent with RBS' 24-month operating cycles, as approved by NRC in Operating License Amendment No. 168 on August 31, 2010. The changes to the Allowable Values are necessary to address the discovery of a non-conservative value in the affected Technical Specification.

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RBG-47193 December 8, 2011 Page 2 of 3 The information supporting the proposed TS changes is provided as follows:

  • Attachment 1 provides the evaluation supporting the proposed changes
  • Attachment 2 contains copies of the mark-up TS pages
  • Attachment 3 provides detailed GL 91-04 evaluation results
  • Attachment 4 provides a list of applicable instruments within the scope of this amendment request
  • Attachment 5 provides the evaluation section of engineering calculation G13.18.3.6*016
  • Attachment 6 lists the commitments contained in this document The proposed TS changes have been reviewed by the RBS Onsite Safety Review Committee. Entergy requests approval of this change by December 7, 2012. Once approved, the amendment will be implemented within 60 days.

If you have any questions or require additional information, please contact Mr. Joseph Clark at 225-381-4177.

I declare under penalty of perjury that the foregoing is true and correct. Executed on December 8, 2011.

Respectfully, err C. oet Director - Nuclear Safety Assurance Attachments:

1. Evaluation of Proposed Changes
2. Markup of Proposed Technical Specification Page Changes
3. Detailed Evaluation Results
4. List of Applicable Instrumentation
5. Calculation
6. List of Commitments cc: U. S. Nuclear Regulatory Commission Region IV 612 East Lamar Blvd., Suite 400 Arlington, TX 76011-4125 NRC Sr. Resident Inspector P. O. Box 1050 St. Francisville, LA 70775

-t RBG-47193 December 8, 2011 Page 3 of 3 Department of Environmental Quality Office of Environmental Compliance Radiological Emergency Planning and Response Section JiYoung Wiley P.O. Box 4312 Baton Rouge, LA 70821-4312 U.S. Nuclear Regulatory Commission Attn: Mr. Alan Wang Washington, DC 20555-0001

Attachment 1 RBG-47193 Evaluation of Proposed Changes RBG-47193 Page 1 of 13

1.0 DESCRIPTION

This letter proposes to amend Appendix A, Technical Specifications (TS), of Facility Operating License No. NPF-47 for River Bend Station (RBS), Unit 1. The amendment will extend the frequency of TS Surveillance Requirement (SR) 3.3.8.1.3, and revise Allowable Values (AV) for certain Functions associated with this SR.

Entergy requests approval of this change by December 7, 2012. As demonstrated in this submittal, the proposed changes do not adversely affect safety.

2.0 PROPOSED CHANGE

S The requested amendment will make the following changes.

1. The Frequency of SR 3.3.8.1.3, "Perform CHANNEL CALIBRATION," is to be extended from 18 months to 24 months. This SR is applicable to TS 3.3.8.1, "Loss of Power (LOP) Instrumentation." The instruments subject to this SR perform the Functions described on Table 3.3.8.1-1 as 4.14 kV emergency bus undervoltage for Divisions 1, 2, and 3. The instrumentation is configured to monitor both "loss of voltage" and "degraded voltage" conditions.
2. The AVs in Table 3.3.8.1-1, "Loss of Power Instrumentation," for the following Functions are being revised:
a. Function 1.a, Divisions 1 and 2 - 4.16 kV Emergency Bus Undervoltage, Loss of Voltage- 4.16 kV Basis
b. Function 1 .d, Divisions 1 and 2 - 4.16 kV Emergency Bus Undervoltage, Degraded Voltage - Time Delay, No LOCA
c. Function 2.a, Division 3 - 4.16 kV Emergency Bus Undervoltage, Loss of Voltage - 4.16 kV Basis
d. Function 2.d, Division 3- 4.16 kV Emergency Bus Undervoltage, Degraded Voltage - Time Delay, No LOCA The specific changes in these AVs are described in Section 4.2 below, and indicated on the mark-up TS page in Attachment 2. As this AV change involves re-calibration of the affected relays (nominally scheduled during a refueling outage), the TS page will be annotated to reflect the delayed implementation of the field changes. Refueling outage no. 17 is scheduled to begin in February 2013.

3.0 BACKGROUND

3.1 Generic Letter 91-04 Changes In NRC GL 91-04 (Reference 1), the NRC provided generic guidance for evaluating a 24-month surveillance test interval for TS SRs that are currently performed at 18-month RBG-47193 Page 2 of 13 intervals. Section 4.0 that follows defines each step outlined by the NRC in Reference 1 and provides a description of the methodology used by RBS to complete the evaluation for the SR being extended from 18 months to a 24-month frequency. The methodology utilized in the RBS drift analysis is similar to that used in the original amendment request for 24-month fuel cycles (LAR 2009-05). There have been minor revisions incorporated into the River Bend drift design guide based on NRC comments or Requests for Additional Information from previous similar submittals, such as the addition of the requirement that 30 samples were generally required to produce a statistically significant sample set.

The proposed TS changes based on Reference 1 are categorized as: changes involving the channel calibration frequency identified as "Channel Calibration Changes."

For each component having a surveillance interval extended, historical surveillance test data and associated maintenance records were reviewed in evaluating the effect on safety. In addition, the licensing basis was reviewed for functions associated with each revision to ensure it was not invalidated. Based on the results of these reviews, it is concluded that there is no adverse effect on plant safety due to increasing the surveillance test intervals from 18 to 24 months with the continued application of SR 3.0.2, which allows a 25% extension (i.e., grace period up to 30 months) to SR frequencies.

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 revised setpoint calculations were developed in accordance with the RBS commitment to the guidance provided in Regulatory Guide 1.105, "Instrument Setpoints" (Reference 3) as implemented by the RBS setpoint methodology (Reference 5). 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. In performing the revised setpoint calculations described above, the use of ISA RP67.04,,Part II (Reference 6), "Method 3" was not utilized.

3.2 Loss of Power Instrumentation Branch Technical Position (BTP) PSB-1 requires that a second level of undervoltage protection, in addition to loss-of-voltage protection be provided to protect safety related equipment from sustained operation at degraded voltage levels that might affect equipment operability. Accordingly, an analytical limit is established based on the maximum bus voltage recovery time during a loss of coolant accident (LOCA) response relative to electrical component (e.g., motors) sequencing and acceleration when loaded on the bus.

Successful operation of the required safety functions of the emergency core cooling systems (ECCS) is dependent upon the availability of adequate power sources for energizing the various components such as pump motors, motor operated valves, and the associated control components. The LOP instrumentation monitors the 4.16 kV RBG-47193 Page 3 of 13 emergency buses. Offsite power is the preferred source of power for the 4.16 kV emergency buses. If the monitors determine that insufficient power is available, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources.

The under-voltage protection scheme at RBS consists of two levels of protection for Class 1 E equipment. The first level is set at approximately 70% of nominal bus voltage with a time delay of three seconds. Following this delay, the Class 1 E distribution system is automatically separated from the offsite power system.

The second level of under-voltage protection is designed to actuate when grid voltages fall below the lowest expected value, which maintains an emergency bus voltage greater than minimum necessary for Class 1 E equipment function. Each divisional 4160 V safety related bus has a dedicated circuit consisting of relays arranged in a 2-out-of-3 coincidence logic with two time delays each. The two separate time delays are for low voltage protection during two conditions of operation: with and without a loss of coolant (LOCA) occurrence. The first time delay is approximately 5 seconds to accommodate normal motor starting transients. Following this delay, an alarm in the main control room alerts the operator to the degraded condition. An occurrence of a LOCA signal subsequent to this degraded voltage condition immediately separates the Class 1 E 4160 V safety related bus from the offsite power system. The second time delay is approximately 60 seconds. After this delay, if the operator has failed to restore adequate voltages, the Class 1 E 4160 V safety related bus is automatically separated from the offsite power system, irrespective of the occurrence of a LOCA.

The Division 1 4160 V safety-related bus is fed directly from preferred transformer RTX-XSR1 C and the Division 2 4160 V safety related bus is fed directly from preferred transformer RTX-XSR1 D. A non-safety 4160 V bus is also fed from each of these preferred transformers. In turn, a third non-safety 4160 V bus can be fed from either one of the upstream non-safety 4160 V buses.

The results of the drift analysis indicated that the projected 30-month drift values for the instruments Division 1 and 2 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage - 4.16 kV Basis (Table 3.3.8.1-1, Function 1.c) and Division 3 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage - 4.16 kV Basis (Table 3.3.8.1-1, Function 2.c) did not exceed the drift allowance provided in the setpoint calculation for these functions.

The TS Bases criteria for the degraded voltage instrumentation requires that, (1) the degraded voltage AVs to 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 to 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.

Generic Letter (GL) 89-10 MOVs are required to perform their design basis function at degraded grid voltage concurrent with a LOCA. An existing operability determination, performed and documented in accordance with the RBS corrective action program, RBG-47193 Page 4 of 13 addresses a portion of the GL 89-10 population. Because all Class 1 E motors were purchased to be capable of starting and accelerating their driven equipment with 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.

However, a group of the motor operated valves governed by GL 89-10 was determined 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 used the results of the offsite grid stability studies as discussed below.

RBS has completed offsite grid stability studies that indicate grid voltage levels remain above 99.5%. RBS has modified the offsite power requirements to ensure that grid voltage is no lower than 97.5%, up from the current limit of 95%. This change resulted in an increase in minimum grid voltage operability limit from 95% to 97.5%. The setpoint for the "low grid voltage" alarm in the main control room was changed from 98% to 98.2%.

In connection with RBS' transition to 24-month fuel cycles, information was added to the TS Bases consistent the NRC staff's position on complying with 10 CFR 50.36 as provided in RIS 2006-17, and further clarified by Technical Specification Task Force (TSTF)-493, Revision 4, and TSTF-09-07 letter to NRC dated February 23, 2009, for non-safety limit-related limiting safety system setting functions. Specifically, the following information was added for the Loss of Power degraded voltage function:

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

4.0 TECHNICAL ANALYSIS

4.1 Generic Letter 91-04 Changes The proposed TS surveillance frequency change from 18 months to 24 months has been categorized - as generally outlined in Reference 1 - as changes involving the channel calibration frequency identified as "Channel Calibration Changes."

4.1.1 Channel Calibration Changes Reference 1 identifies seven steps for the evaluation of instrumentation calibration changes.

STEP 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.

RBG-47193 Page 5 of 13 EVALUATION The effect of longer calibration intervals on the TS instrumentation was evaluated by performing a review of the surveillance test history for the affected instrumentation including, where appropriate, an instrument drift study. In performing the historical evaluation, an effort was made to retrieve recorded channel calibration data for associated instruments for at least five operating cycles prior to and including the Spring 2011 refueling outage. By obtaining this past recorded calibration data, an acceptable basis for drawing conclusions about the expectation of satisfactory performance can be made.

The failure history evaluation and drift study found that instrument drift has not exceeded the current Technical Specification Allowable Values except for the SR test failures discussed in Attachment 3. The specific evaluation basis supporting this conclusion is also discussed in Attachment 3.

STEP 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.

EVALUATION The effect of longer calibration intervals on the TS instrumentation was evaluated by performing an instrument drift study. In performing the drift study, an effort was made to retrieve recorded channel calibration data for associated instruments for at least five operating cycles prior to and including the Spring 2011 refueling outage. By obtaining this past recorded calibration data, a true representation of instrument drift was determined (except in cases where all collected data still resulted in insufficient data for valid statistical analysis).

The methodology used to perform the drift analysis is consistent with the methodology utilized by other utilities requesting transition to a 24-Month fuel cycle. The methodology is also based on Electric Power Research Institute (EPRI) TR-103335, "Statistical Analysis of Instrument Calibration Data" (Reference 7).

STEP 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.

EVALUATION In accordance with the methodology described in the EOI drift design guide, the magnitude of instrument drift has been determined with a high degree of confidence and RBG-47193 Page 6 of 13 a high degree of probability (at least 95/95) for a bounding calibration interval of 30 months for each instrument make, model, and range. For instruments not in service long enough to establish a projected drift value or where an insufficient number of calibrations have been performed to utilize the statistical methods (i.e., fewer than 30 calibrations for any given group of instruments), the SR frequency is proposed to be extended to a 24-month interval based on other, more frequent testing or justification obtained from analysis as presented in Attachment 3. The list of affected channels by TS section, including make, model, and range, is provided in Attachment 4.

STEP 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 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.

EVALUATION The projected drift values were compared to the design allowances as calculated in the associated instrument setpoint analyses. If the projected drift for an instrument fell outside the existing setpoint calculation design allowances, then the analysis of the setpoint, allowable value, and/or analytical limit was reviewed. Setpoint calculations were revised, or will be revised prior to implementation, as necessary, to accommodate appropriate drift values. When the 30-month projected drift value for an instrument could be accommodated within the existing or revised setpoint analysis, the SR frequency was changed to "24 months" with no change to the TS allowable value or licensing basis analytical limit.

As necessary, 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 revised setpoint calculations were developed in accordance with RBS commitment to the guidance provided in RG 1.105 (Reference 3) as implemented by the RBS setpoint methodology (Reference 5), ISA Standard 67.04, 1975 (Reference 6), and IEEE Standard 741-1997, "Criteria for the Protection of Class 1E Power Systems and Equipment in Nuclear Power Generating Stations" (Reference 9). These calculations determined the instrument loop uncertainty, setpoint, and allowable value for the affected function. The allowable values were determined in a manner suitable to establish limits for their application.

STEP 5: Confirm that the projected instrument errors caused by drift are acceptable for control of plant parameters to effect a safe shutdown with the associated instrumentation.

RBG-47193 Page 7 of 13 EVALUATION As discussed in the previous sections, the calculated drift values have been compared to drift allowances in the RBS design basis. In no case was a change to the safe shutdown analysis required to support any change to a 24-month frequency.

STEP 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.

EVALUATION Applicable surveillance test procedures are being reviewed and acceptance criteria updated to incorporate the necessary changes resulting from any revision to setpoint calculations. Any necessary changes resulting from the reviews will be incorporated into the instrument surveillance procedures prior to the implementation of the 24-month surveillance test frequency. Existing plant processes ensure 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.

STEP 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.

EVALUATION 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 above, 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 allowable value and instruments whose performance is not as assumed in the drift or setpoint analysis. When as-found conditions are outside the allowable value, 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.

In addition, the trending program will address calibration as-found data found to be outside of the "as-found tolerance" (AFT). This AFT is based on the expected 30-month drift for the instruments. The trending program will require that any time a calibration as-found value is found outside the AFT, the occurrence will be entered into the RBS corrective action program and the instrument performance evaluated to assure that it is still enveloped by the assumptions in the drift or setpoint analysis. This will allow the trending program to evaluate AFAL values to verify that the performance of the instruments is within expected boundaries and that adverse trends are detected and evaluated. This evaluation will be conducted for three (3) 24-month calibration intervals RBG-47193 Page 8 of 13 to ensure the assumptions in the setpoint calculations continue to be valid. If this evaluation indicates that instrument performance is not consistent with assumptions, corrective actions will be taken in accordance with station corrective action program requirements.

4.2 Allowable Value changes Loss of Voltaqe Setting Analysis The loss of voltage relay protection is provided to ensure that sustained degraded grid conditions under non-LOCA scenarios do not damage the safety related equipment.

The loss of voltage relay settings are selected to limit the magnitude and duration of an under-voltage condition on safety related buses. The setting should be low enough to ensure that nuisance tripping does not occur from anticipated dynamic effects such as motor starting. RBS' safety related motors are capable of carrying load for 60 seconds at 70% of rated voltage. When the motors experience terminal voltage below 70%, they may not function or may be damaged. Likewise, they may not function or may be damaged at terminal voltage below 70% for a duration longer than 60 seconds. The analytical limit (AL) for the relays is selected by determining the Class 1 E 4160-volt bus voltage such that the worst-case motor has at least 70% terminal voltage. The AL for the degraded voltage relays (no LOCA) time delay is 60 seconds. AVs are determined by applying the appropriate margins and uncertainty to these ALs.

Loss of Voltage Lower Analytical Limit Based on the methodology described above, the lower AL and equipment terminal voltages for the applicable 4160-volt bus are found using approved calculations. The summary for the results is provided below in Table 1 and 2.

Table 1 Bus Chosen Lower AL Corresponding Grid Voltage ENS-SWG1A 2934.00 VAC 77%

ENS-SWG1 B 2934.00 VAC 73.44%

E22-S004 2921.00 VAC 76.86%

At the above ALs, the following loads have the lowest steady state terminal voltage (greater than or equal to 70% of rated voltage):

Table 2 Component Bus Load Terminal Voltage

(% of Rated Voltage)

HVR-UC1A (containment unit cooler "A") Div 1 70.49%

HVR-UC1 B (containment unit cooler "B") Div 2 70.56%

HVP-FN3A (diesel generator room exh. fan) Div 3 70.40%

RBG-47193 Page 9 of 13 The existing AVs and Nominal Trip Setpoints considered have both upper and lower limits. For the revised settings, an upper limit is calculated for the degraded voltage relay no-LOCA time delay. The time delay relay will not have a lower limit. A lower limit is calculated for the loss of voltage relay dropout. The loss of voltage relay will not have an upper limit. Spurious trip avoidance analysis will ensure that these relays, iffound drifted in the upper / lower limit not calculated, will not trip under unanalyzed conditions.

The evaluation section of calculation G13.18.3.6*016 is included as Attachment 5 to this amendment request for reference.

Loss of Voltage No-LOCA Time Delay Allowable Values The following table shows the new revised TS limits:

Divisions 1 and 2 Specification Existing AVs Revised AVs T.S. 3.3.8.1-1, Function 1.a. 1 2850 V and S 3090 V >3005 V and < 3302 V

> 53.4 seconds T.S. 3.3.8.1-1, Function 1 .d. I~6. eod and > 46.59 70 seconds eod and

<566.6 seconds 2831 V and < 3259 V >3019 V and< 3325 V T.S. 3.3.8.1-1, Function 2.d. >56. 53.4 seconds eod and

<566.6 seconds

> 44.7 48 seconds

<54.82 eod and seconds

5.0 REGULATORY ANALYSIS

5.1 NO SIGNIFICANT HAZARDS CONSIDERATION Entergy has evaluated whether 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," discussed below.

The requested change would affect certain Technical Specification (TS) Surveillance Requirement (SR) frequencies that are specified as "18 months" by revising them to "24 months" in accordance with the guidance of Generic Letter (GL) 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24 Month Fuel Cycle,"

dated April 2, 1991.

RBG-47193 Page 10 of 13

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

Response: No.

SR extension:

The proposed TS change revises a surveillance testing interval to facilitate a change in the operating cycle length. The proposed TS change involves no physical alteration of the plant. The proposed TS change does not degrade the performance of, or increase the challenges to, any safety systems assumed to function in the accident analysis. The proposed TS change does not adversely affect the usefulness of the SR in evaluating the operability of required system and components, or the way in which the surveillance is performed. In addition, the frequency of surveillance testing is not considered an initiator of any analyzed accident, nor does a revision to the frequency introduce any accident initiators.

Therefore, the proposed change does not involve a significant increase in the probability of an accident previously evaluated.

The consequences of a previously evaluated accident are not significantly increased.

The proposed change does not affect the performance of any equipment credited to mitigate the radiological consequences of an accident. Evaluation of the proposed TS change has demonstrated that the availability of credited equipment is not significantly affected because of other more frequent testing that is performed, the availability of redundant systems and equipment, and the high reliability of the equipment. Historical review of surveillance test results and associated maintenance records did not find evidence of failures that would invalidate the above conclusions.

AV changes:

The change in the degraded voltage protection voltage and time delay allowable values allows the protection scheme to function as originally designed. (This change will involve alteration of nominal trip setpoints in the field, also to be reflected in revisions to the calibration procedures.) The proposed allowable values ensure that the Class 1 E distribution system remains connected to the offsite power system when adequate offsite voltage is available and motor starting transients are considered. Calculations have demonstrated that adequate margin is present to support the decrease in the minimum allowable Division 3 degraded voltage. The proposed time delay continues to provide equipment protection while preventing a premature separation from offsite power. The diesel start due to a Loss of Coolant Accident signal is not adversely affected by this change. During an actual degraded voltage condition, the degraded voltage time delays will continue to isolate the Class 1 E distribution system from offsite power before the diesel is ready to assume the emergency loads, which is the limiting time basis for mitigating system responses to the accident. For this reason, the existing loss of power / loss of coolant accident analysis continues to be valid.

RBG-47193 Page 11 of 13 Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

Response: No.

SR extension:

The proposed TS change revises a surveillance testing interval to facilitate a change in the operating cycle length. The proposed TS change does not introduce any failure mechanisms of a different type than those previously evaluated, since there are no physical changes being made to the facility. No new or different equipment is being installed. No installed equipment is being operated in a different manner. As a result, no new failure modes are being introduced. The way surveillance tests are performed remains unchanged. A historical review of surveillance test results and associated maintenance records indicated there was no evidence of any failures that would invalidate the above conclusions.

AV changes:

The proposed change involves the revision of degraded voltage protection voltage and time delay allowable values to satisfy existing design requirements.

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

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

Response: No.

SR extension:

The proposed TS change revises a surveillance testing interval to facilitate a change in the operating cycle length. The effect of this change on system availability is not significant, based on other more frequent testing that is performed, the existence of redundant systems and equipment, and overall system reliability. Evaluation has shown there is no evidence of time dependent failures that would affect the availability of the systems. The proposed change does not adversely affect the condition or performance of structures, systems, and components relied upon for accident mitigation. The proposed change does not result in any hardware changes or in any changes to the analytical limits assumed in accident analyses. Existing operating margin between plant conditions and actual plant setpoints is not significantly reduced due to these changes. The proposed change does not significantly affect any safety analysis assumptions or results.

RBG-47193 Page 12 of 13 AV changes:

The proposed protection voltage allowable values are low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient voltage is available to the required equipment. The proposed time delay continues to provide equipment protection while preventing a premature separation from offsite power.

The diesel start due to a Loss of Coolant Accident signal is not adversely affected by this change. During an actual degraded voltage condition, the degraded voltage time delays will continue to isolate the Class 1 E distribution system from off site power before the diesel is ready to assume the emergency loads.

Therefore, the proposed change does not involve a significant reduction in a margin of safety.

Based on the above, Entergy concludes that the proposed amendment present no 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.

5.2 APPLICABLE REGULATORY REQUIREMENTS / CRITERIA Regulatory requirement 10 CFR 50.36, 'Technical specifications," provides the content required in a licensee's TS. Specifically, 10 CFR 50.36(c)(3) requires that the TS include surveillance requirements. The proposed SR frequency changes continue to support the requirements of 10 CFR 50.36(c)(3) 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 are met.

NRC GL 91-04 provides generic guidance for evaluating a 24 month surveillance test interval for TS SRs. This request for license amendment provides the RBS specific evaluation of each step outlined by the NRC in GL 91-04 and provides a description of the methodology used by RBS to complete the evaluation for each specific TS SR being revised.

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 the proposed manner, (2) such activities will be conducted in compliance withf the Commission's 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.

6.0 ENVIRONMENTAL CONSIDERATION

A review 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 significant increase in the RBG-47193 Page 13 of 13 amounts of any effluent 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.

7.0 REFERENCES

(1) NRC Generic Letter 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991 (2) Regulatory Guide 1.52, "Design, Inspection, and Testing Criteria for Air Filtration and Adsorption Units of Post-Accident Engineered-Safety-Feature Atmosphere Cleanup Systems in Light-Water-Cooled Nuclear Power Plants," Revision 2, dated March 1978 (3) Regulatory Guide 1.105, "Instrument Setpoints," Revision 1, dated November 1976 (4) Regulatory Guide 1.197, "Demonstrating Control Room Envelope Integrity at Nuclear Power Reactors," Revision 0, May 2003 (5) EN-IC-S-007-R Rev. 0 "Instrument Loop Uncertainty & Setpoint Calculations" (6) Instrument Society of America (ISA) S67.04, "Setpoints for Nuclear Safety-Related Instrumentation," Part I, and ISA RP67.04, "Methodologies for the Determination of Setpoints for Nuclear Safety-Related Instrumentation," Part II, 1994 (7) EPRI TR-103335, "Statistical Analysis of Instrument Calibration Data," Revision 1, dated October 1998 (8) NRC Status Report on the Staff review of EPRI Technical Report (TR)-103335, Revision 0, Status Report, dated December 1, 1997 (9) IEEE Standard 741-1997, "Criteria for the Protection of Class 1 E Power Systems and Equipment in Nuclear Power Generating Stations"

ATTACHMENT 2 RBG-47193 Mark-up of proposed changes to Technical Specifications (pages 3.3-73 and 3.3-74)

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. m~onths ( -Z4 SR 3.3.8.1.4 Perform LOGIC SYSTEM FUNCTIONAL TEST. J 24 months RIVER BEND 3.3-73 Amendment No. 84,168

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 SR 3.3.8.1.2 Ž3005 Vand :r3302V(Note 1)3 SR 3.3.8.1.3 SR 3.3.8.1.4
b. Loss of Voltage - Time Delay SR 3.3.8.1.3 _ 2.67 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 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4
d. Degraded Voltage - Time Delay, No SR 3.3.8.1.3 *6

_53..6 second an d.6co ds LOCA SR 3.3.8.1.4 Ž46.59 seconds and 2*57.07 seconds (Note 1)

e. Degraded Voltage - Time Delay, SR 3.3.8.1.3 LOCA SR 3.3.8.1.4 < 5.7 seconds
2. Division 3 - 4.16 kV Emergency Bus Undervoltage
a. Loss of Voltage - 4.16 kV basis 2 SR 3.3.8.1.1 ..2Y8 V nd 32 SVý SR 3.3.8.1.3 >3019 V and <3325 V(Note1)

SR 3.3.8.1.4

b. Loss of Voltage - Time Delay 2 SR 3.3.8.1.3 *-2.67 seconds and SR 3.3.8.1.4
  • 3.33 seconds
c. Degraded Voltage - 4.16 kV basis SR 3.3.8.1.1 Ž:3674.0 Vand :*3721.2 V SR 3.3.8.1.2 SR 3.3.8.1.3 SR 3.3.8.1.4
d. Degraded Voltage - Time Delay, No SR 3.3.8.1.3 r !(53. se nYan5* 6co as LOCA SR 3.3.8.1.4 Žt44.7 seconds and *954.82 seconds (Note 1)
e. Degraded Voltage - Time Delay, SR 3.3.8.1.2 Ž4.5 seconds and LOCA SR 3.3.8.1.3 < 5.7 seconds SR 3.3.8.1.4

( (Note 1 - These values become effecttve as of the enofRI)

Iýýn I II ofIIR F1I RIVER BEND 3.3-74 Amendment No. 81 95 128 147 151,

ATTACHMENT 3 RBG-47193 Detailed Evaluation Results for SR Extension RBG-47193 Page 1 of 4

1. BACKGROUND Technical Specification (TS) Surveillance Requirement (SR) frequency changes are required to accommodate a 24-month fuel cycle for River Bend. The proposed changes associated with this submittal were evaluated in accordance with the guidance provided in NRC Generic Letter (GL) 91-04, "Changes in Technical Specification Surveillance Intervals to Accommodate a 24-Month Fuel Cycle," dated April 2, 1991. GL 91-04 provides NRC Staff guidance that identifies the types of information that must be addressed when proposing extensions of TS SR frequency intervals from 18 months to 24 months.

Historical surveillance test data and associated maintenance records were reviewed in evaluating the effect of these changes on safety. In addition, the licensing basis was reviewed to ensure it was not invalidated. Based on the results of these reviews, it is concluded that there is no adverse effect on plant safety due to increasing the surveillance test intervals from 18 to 24 months with the continued application of the SR 3.0.2 25% grace period.

GL 91-04 addressed steam generator inspections, which are not applicable to River Bend and therefore are not discussed in this submittal. Additionally, the GL addressed interval extensions to leak rate testing pursuant to 10 CFR Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-Cooled Power Reactors," which is also not addressed by the River Bend submittal because individual leak testing requirements have been replaced by the Primary Containment Leakage Rate Testing Program.

2. EVALUATION In GL 91-04, the NRC provided generic guidance for evaluating a 24 month surveillance test interval for TS SRs. Attachment 1 of this submittal defines each step outlined by the NRC in GL 91-04 and provides a description of the methodology used by River Bend to complete the evaluation for each specific TS SR line item. The methodology utilized in the RBS drift analysis is similar to that used in the original amendment request for 24-month fuel cycles (LAR 2009-05). There have been minor revisions incorporated into the River Bend drift design guide based on NRC comments or Requests for Additional Information from previous similar submittals, such as the addition of the requirement that 30 samples were generally required to produce a statistically significant sample set.

For each of the identified surveillances, an effort was made to retrieve the five most recent surveillance test performances through the Spring 2011 refueling outage (i.e.,

approximately seven years of history). This provided approximately three 30-month surveillance periods of data to identify any repetitive problems. It has been concluded, based on engineering judgment, that three 30 month periods provide adequate performance test history. In some instances, additional surveillance performances were included when insufficient data was available for adequate statistical analysis of instrument drift. Further references to performance history reflect evaluations of the five most recent performances available through the Spring 2011 outage, unless otherwise stated.

In addition to evaluating the historical drift associated with current 18-month calibrations, the failure history of each 18-month surveillance was also evaluated. With the extension RBG-47193 Page 2 of 4 of the testing frequency to 24 months, there will be a longer period between each surveillance performance. If a failure that results in the loss of the associated safety function should occur during the operating cycle, that would only be detected by the performance of the 18-month TS SR, then the increase in the surveillance testing interval might result in a decrease in the associated function's availability. Furthermore, potential common failures of similar components tested by different surveillances were also evaluated. This additional evaluation determined whether there is evidence of repetitive failures among similar plant components.

The surveillance failures detailed with each SR exclude failures that:

(a) Did not affect a TS safety function or TS operability, (b) Are detectable by required testing performed more frequently than the 18 month surveillance being extended, or (c) Where the cause can be attributed to an associated event such as a preventative maintenance task, human error, previous modification or previously existing design deficiency, or that were subsequently re-performed successfully with no intervening corrective maintenance (e.g., plant conditions or malfunctioning measurement and test equipment (M&TE) may have caused aborting the test performance).

These categories of failures are not related to potential unavailability due to testing interval extension, and are therefore not listed or further evaluated in this submittal.

The following sections summarize the results of the failure history evaluation. The evaluation confirmed that the impact on system availability, if any, would be small as a result of the change to a 24-month testing frequency.

The proposed TS change related to GL 91-04 test interval extensions has been categorized as a change involving the channel calibration frequency identified as "Channel Calibration Changes."

A. Channel Calibration Change NRC GL 91-04 requires that licensees address instrument drift when proposing an increase in the surveillance interval for calibrating instruments that perform safety functions including providing the capability for safe shutdown. The effect of the increased calibration interval on instrument errors must be addressed because instrument errors caused by drift were considered when determining safety system setpoints and when performing safety analyses. NRC GL 91-04 identifies seven steps for the evaluation of instrumentation calibration changes. These seven steps are discussed in Attachment 1 to this submittal. In that discussion, a description of the methodology used by River Bend for each step is summarized. The detailed methodology is provided in Attachment 3.

The following are the calibration-related TS SRs being proposed for revision from 18 months to 24 months, for a maximum interval of 30 months (considering the 25% grace period allowed by TS SR 3.0.2). In each instance, the instrument channel loop drift was evaluated in accordance with Setpoint Methodology EN-IC-S-007-R Rev. 0 "Methodology For The Generation of Instrument.Loop Uncertainty & Setpoint Calculations" and Drift Design Guide ECH-NE-08-00015, Revision 0 "Instrument Drift Analysis Design Guide" The projected 30-month drift values for many of the instruments analyzed from the historical as-found / as-left evaluation shows sufficient margin RBG-47193 Page 3 of 4 between the current plant setpoint and the allowable value to compensate for the 30-month drift. For each instrument function that has a channel calibration proposed frequency change to 24 months, the associated setpoint calculation assumes (or will be revised prior to implementation to assume) a consistent or conservative drift value appropriate for a 24-month calibration interval. All revised setpoint calculations have been (or will be) completed in accordance with the guidance provided in RG 1.105, Rev.1 "Instrument Setpoints," as implemented by the River Bend setpoint methodology, and the Instrument Society of America (ISA) Standard 67.04, 1975. These calculations determine the instrument uncertainties, setpoints, and allowable values for the affected functions. The allowable values have been determined in a manner suitable to establish limits for their application. As such, the TS allowable values ensure that sufficient margins are maintained in the applicable safety analyses to confirm the affected instruments are capable of performing their intended design function. In addition, review of the applicable safety analysis concluded that the setpoints, revised allowable values, and projected 30-month drift confirmed the safety limits and safety analysis assumptions remain bounding.

Below is a summary of the specific application of this methodology to the River Bend 24-month fuel cycle extension project.

3.3.8.1 Loss of Power (LOP) Instrumentation Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power sources for energizing the various components such as pump motors, motor operated valves, and the associated control components. The LOP instrumentation monitors the 4.16 kV emergency buses. Offsite power is the preferred source of power for the 4.16 kV emergency buses. If the monitors determine that insufficient power is available, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources.

SR 3.3.8.1.3 Perform CHANNEL CALIBRATION.

Function 1.a Division 1 and 2 - 4.16 kV Emergency Bus Undervoltage - Loss of Voltage - 4.16 kV basis Function 1 .b Division 1 and 2 - 4.16 kV Emergency Bus Undervoltage - Loss of Voltage - Time Delay Function 1.c Division 1 and 2 -4.16 kV Emergency Bus Undervoltage - Degraded Voltage - 4.16 kV basis Function 1 .d Division 1 and 2 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage - Time Delay, No LOCA Function 1.e Division 1 and 2 -4.16 kV Emergency Bus Undervoltage - Degraded Voltage - Time Delay, LOCA Function 2.a Division 3 -4.16 kV Emergency Bus Undervoltage - Loss of Voltage -

4.16 kV basis Function 2.b Division 3 - 4.16 kV Emergency Bus Undervoltage - Loss of Voltage -

Time Delay Function 2.c Division 3- 4.16 kV Emergency Bus Undervoltage - Degraded Voltage - 4.16 kV basis RBG-47193 Page 4 of 4 Function 2.d Division 3 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage - Time Delay, No LOCA Function 2.e Division 3 - 4.16 kV Emergency Bus Undervoltage - Degraded Voltage - Time Delay, LOCA The results of the drift analysis indicate that the projected 30 month drift values for the instruments are acceptable.

A review of the applicable River Bend surveillance history for these channels demonstrated that the as-found trip setpoint for these functions had only two previous failures of TS required allowable values that would have been detected solely by the periodic performance of this SR.

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 ABB 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 ABB Model ITE-27N relay and tested satisfactorily. Subsequent evaluation concluded the relay time delay 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.

There are a total of two failures identified over the review period relative to ASEA Brown Boveri relays. One failure was Model ITE-62K and one failure was Model ITE-27H. 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. There are no time-based mechanisms apparent in these failures.

Therefore, each failure is unique and any subsequent failure would not result in a significant impact on system/component availability As such, the impact, if any, on system availability is minimal from the proposed change to a 24-month testing frequency. Based on the history of system performance, the impact of this change on safety, if any, is small.

ATTACHMENT 4 RBG-47193 List of Applicable Instrumentation RBG-47193 Page 1 of 3 Requirement Mark No. Calculation Manufacturer Model No.

SR 3.3.8.1.3-1.a ENS-SWG1A- G13.18.6.3-006 ASEA BROWN ITE-27H 27-1A BOVERI SR 3.3.8.1.3-l.a ENS-SWGIA- G13.18.6.3-006 ASEA BROWN ITE-27H 27-1B BOVERI SR 3.3.8.1.3-l.a ENS-SWG1A- G13.18.6.3-006 ASEA BROWN ITE-27H 27-1C BOVERI SR 3.3.8.1.3-l.a ENS-SWG1 B- G13.18.6.3-006 ASEA BROWN ITE-27H 27-1A BOVERI SR 3.3.8.1.3-l.a ENS-SWG1 B- G13.18.6.3-006 ASEA BROWN ITE-27H 27-1B BOVERI SR 3.3.8.1.3-l.a ENS-SWG1 B- G13.18.6.3-006 ASEA BROWN ITE-27H 27-1C BOVERI SR 3.3.8.1.3-1.b ENS-SWG1A- G13.18.6.3-009 ASEA BROWN ITE-62K 62-1 BOVERI SR 3.3.8.1.3-1.b ENS-SWG1 B- G13.18.6.3-009 ASEA BROWN ITE-62K 62-1 BOVERI SR 3.3.8.1.3-1.c ENS-SWG1A- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-1.c ENS-SWG1A- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-1.c ENS-SWGIA- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-1.c ENS-SWG1 B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-1.c ENS-SWG1 B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-1.c ENS-SWG1B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-1.c ENS-SWG1A- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-1.c ENS-SWGIA- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-1.c ENS-SWG1A- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-1.c ENS-SWGIB- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8,1.3-1.c ENS-SWG1B- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8,1.3-1.c ENS-SWG1B- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-1.d ENS-SWG1A- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8,1.3-1.d ENS-SWG1A- G13.18.6.3-007 ASEA BROWN ITE-27N I 27/62-2B BOVERI RBG-47193 Page 2 of 3 SR 3.3.8.1.3-1.d ENS-SWG1A- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-1.d ENS-SWG1B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-1.d ENS-SWG1 B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-1.d ENS-SWG1B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-1.d ENS-SWG1A- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-1.d ENS-SWGIA- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-1.d ENS-SWG1A- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-1.d ENS-SWG1 B- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-1.d ENS-SWG1B- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-1.d ENS-SWG1 B- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-1.d ENS-SWGIA- G13.18.6.3-009 ASEA BROWN ITE-62K 62-2 BOVERI SR 3.3.8.1.3-1.d ENS-SWG1 B- G13.18.6.3-009 ASEA BROWN ITE-62K 62-2 BOVERI SR 3.3.8.1.3-i.e ENS-SWGIA- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-i.e ENS-SWGlA- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-i.e ENS-SWG1A- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-i.e ENS-SWG1B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-i.e ENS-SWG1B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-i.e ENS-SWG1B- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8.1.3-i.e ENS-SWG1A- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8.1.3-i.e ENS-SWGIA- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8,1.3-i.e ENS-SWG1A- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2C BOVERI SR 3.3.8,1.3-i.e ENS-SWG1B- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2A BOVERI SR 3.3.8,1.3-i.e ENS-SWG1 B- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2B BOVERI SR 3.3.8.1.3-i.e ENS-SWG1B- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2C BOVERI RBG-47193 Page 3 of 3 SR 3.3.8.1.3-i.e ENS-SWG1A- G13.18.6.3-009 ASEA BROWN ITE-62K 62-6 BOVERI SR 3.3.8.1.3-i.e ENS-SWG1B- G13.18.6.3-009 ASEA BROWN ITE-62K 62-6 BOVERI SR 3.3.8.1.3-2.a E22-S004- G13.18.6.3-012 GENERAL NGV1 3B 27N1 ELECTRIC CO SR 3.3.8.1.3-2.a E22-S004- G13.18.6.3-012 GENERAL NGV1 3B 27N2 ELECTRIC CO SR 3.3.8.1.3-2.a E22-S004- G13.18.6.3-012 GENERAL NGV13B 27S1 ELECTRIC CO SR 3.3.8.1.3-2.a E22-S004- G13.18.6.3-012 GENERAL NGV13B 27S2 ELECTRIC CO SR 3.3.8.1.3-2.a E22-S004- G13.18.6.3-012 GENERAL NGV13B 27S3 ELECTRIC CO SR 3.3.8.1.3-2.a E22-S004- G13.18.6.3-012 GENERAL NGV13B 27S4 ELECTRIC CO SR 3.3.8.1.3-2.b E22-S004- G13.18.6.3-013 GENERAL SAM11B 62S1 ELECTRIC CO SR 3.3.8.1.3-2.b E22-S004- G13.18.6.3-013 GENERAL SAM11B 62S2 ELECTRIC CO SR 3.3.8.1.3-2.b E22-S004- G13.18.6.3-014 AMERACE ETR 62S3 CORP (Agastat)

SR 3.3.8.1.3-2.b E22-S004- G13.18.6.3-014 AMERACE ETR 62S4 CORP (Agastat)

SR 3.3.8.1.3-2.c E22-S004- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-1 BOVERI SR 3.3.8.1.3-2.c E22-S004- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2 BOVERI SR 3.3.8.1.3-2.c E22-S004- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-1 BOVERI SR 3.3.8.1.3-2.c E22-S004- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2 BOVERI SR 3.3.8.1.3-2.d E22-S004- G13.18.6.3-014 AMERACE ETR14D3E004 62S5 CORP (Agastat)

SR 3.3.8.1.3-2.d E22-S004- G13.18.6.3-014 AMERACE ETR14D3EO04 62S6 CORP (Agastat)

SR 3.3.8.1.3-2.e E22-S004- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-1 BOVERI SR 3.3.8.1.3-2.e E22-S004- G13.18.6.3-007 ASEA BROWN ITE-27N 27/62-2 BOVERI SR 3.3.8.1.3-2.e E22-S004- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-1 BOVERI SR 3.3.8.1.3-2.e E22-S004- G13.18.6.3-008 ASEA BROWN ITE-27N 27/62-2 BOVERI

ATTACHMENT 5 RBG-47193 Calculation (evaluation section only)

1. G13.18.3.6*016, Degraded Voltage Calculation For Class 1E Buses and 480v Motor Operated Valves

El ANO-1 [:1 ANO-2 LI GGNS [] IP-2 [] IP-3 LI PLP El JAF [-IPNPS E RBS 0 VY [] W3 El NP-GGNS-3 [L NP-RBS-3 CALCULATION EC # 3171..__5 Page I of 12 COVER PAGE Design Basis Calc. E*YES [--1 NO F-1 CALCULATION [*EC Markup Calculation No: G13.18.3.6"016 Revision: 02

Title:

Degraded Voltage Calculation for Class IE Buses and 480V Editorial:

Motor Operated Valves El YES EZ NO System(s): 999 Review Org (Department): Design Electrical Safety Class: Component/Equipment/Structure Type/Number:

E Safety / Quality Related Various F- Augmented Quality Program El Non-Safety Related Document Type: ENG01 Keywords (Description/Topical Codes):

Degraded Voltage MOV Terminal Voltage IEEE 741 REVIEWS Name/Signature/Date Name/Signature/Date Name/Signature/Date Mohit Malik Jason Arms Paul Matzke Responsible Engineer Z Design Verifier Supervisor/Approval F- Reviewer

[-_ Comments Attached El Comments Attached

CALCULATION CALCULATION NO: G13.18.3.6"016 REFERENCE SHEET REVISION: 02 I. EC Markups Incorporated NONE II. Relationships: Sht Rev Input Output Impact Tracking No.

Doc Doc Y/N

1. G13.18.3.1-004 0 U U Y CR-RBS-2011-04838 CA6
2. G13.18.3.1-005 0 U Y CR-RBS-2011-04838 CA6 G13.18.3.6*018 4 0 N _

3.

III. CROSS

REFERENCES:

3.1 - IEEE 741-1997, IEEE Standard Criteria for The Protection of Class 1E Power Systems (Attachment 12A. 14) 3.2 - NEMA MG 1 (Attachment 12A. 18)

IV. SOFTWARE USED:

Title:

OTI ETAP Version/Release: 7.1.ON Disk/CD No.

Title:

MS Excel Version/Release: 2003 Disk/CD No.

All computer files associated with this calculation are stored on engineering drive folder - \DE Electrical\CALCS\G 13.18.3.6 016\

V. DISK/CDS INCLUDED:

Title:

Version/Release Disk/CD No.

VI. OTHER CHANGES:

Revision Record of Revision Revision 01 being issued to implement changes as a result ofCR-RBS-2008-03911 and associated outstanding hits against G(13.18.3.6*016 Rev.00. This revision also supersedes 01 calculation E-225 by calculating MOV terminal voltage using ETAP. Note that MOV motor torque calculations in E-225 have been moved to the mechanical MOV calculation G13.18.2.3*325. This calculation revision incorporates the changes to Division III 120/240 VAC distribution panel loading as suggested by G313.18.3.6*016 RevOOO Addendum A.

1. Moved Attachments 12A.01-07, 12A.09, 12A.10 and 12A.12 to calculation G13.18.3.6*018 Rev.002.
2. Referenced the corresponding G 13.18.3.6*018 calculation attachment number in the calculation text.
3. Corrected a typographical error in Section 6.4 - Renumbered table in Section 6.4 to Table 6.3 as Table 6.2 already existed in Section 6.2 of the calculation.

This Engineering Change markup establishes 02 EC- 1. The Lower Analytical Limit for the Loss of Voltage relays.

31715 2. MOV and motor starting terminal voltage during a transient just above the Lower Analytical Limit reset.

- I

4.0 - Table of Contents 5 .0 P u rp o se ................................................................................................................................................. 5 6 .0 C o n clu sio n ............................................................................................................................................ 5 7.0 Input and Design Criteria ........................................................................................................... 9 8 .0 A ssu m p tio n s ......................................................................................................................................... 9 9.0 M ethod of Analysis ............................................................................................................................... 9 10.0 Available M argin ................................................................................................................................ 10 1 1.0 C a lcu la tio n s ........................................................................................................................................ 10 12 .0 A tta ch m en ts ........................................................................................................................................ 12

5.0 Purpose The purpose of this Engineering Change markup is to establish the Analytical Limit for the Loss of Voltage Relays. The Analytical Limit established here will be used to establish Technical Specification limits and setpoints for the Loss of Voltage Relays. Non-design basis setpoint calculations have been prepared supporting the LAR submittal for Tech Spec change of the allowable values for the Division 1, 2, and 3 Loss of Voltage relay voltage and the degraded voltage relay No-LOCA time delay settings.

This markup also evaluates the MOV and motor starting voltages at the Lower Analytical Limit reset.

The markup shows that the MOVs and motor starting voltages are adequate at a condition where grid is degraded below 97.5% and the degraded voltage relay drop out is set at the Lower Analytical Limit.

This analysis is a supplement to that which is found in G13.18.3.6*016 rev 2, which examines the adequacy of the degraded voltage relays while employing the methodology contained in IEEE 741-1997.

The analysis added by this EC markup is the more conservative methodology, therefore the output voltages of this analysis are bounding.

6.0 Conclusion A. Loss of Voltage Relay Analysis:

The analytical limit for Divisions I, II, and III 4160V Loss of Voltage relays are:

ENS-SWG1A - 2950.0 V (Att. 12B.14 and 12B.17)

ENS-SWG1B - 2950.0 V (Att. 12B.15 and 12B.17)

E22-S004 - 2935.0 V (Att. 12B.16 and 12B.17)

The Analytical Limits have been calculated using ETAP Version 7.1.ON and are tabulated in Sections 11.1 and 11.2 of this calculation. These analytical limits are inputs to G13.18.3.1-004 and G13.18.3.1-005 in which relay setpoints are computed using the GE setpoint methodology (7224.300-000-001B).

The Upper Analytical limit for the relays is not calculated. Spurious trip analysis provided in calculations G13.18.3.1-004 and G13.18.3.1-005 show that the Loss of Voltage relays will not drop out during a transient. The Lower Analytical Limit reset transient is used to provide the minimum voltage on the safety related buses during the transient. See Table 11.3 provided in this calculation markup.

A.6.1 Motors:

No motors were found to have less than 70% steady state terminal voltage at the Loss of Voltage relay Lower Analytical Limit.

A.6.2 Safety Related Protective Device Operation at the Loss of Voltage Relay Analytical Limit:

Overcurrent protective device settings have been reviewed to ensure tripping of motors on overload will not occur at the Lower Analytical Limit for the Loss of Voltage relays if operated for time < 60 seconds. NEMA MG-1 specifies that AC induction motors can be operated at

+10% of rated voltage. Since motors are constant power devices when in full load, a decrease in voltage will result in a higher current. Higher current results in internal resistive heating of the motor. Motors are equipped with overload protection to protect against over heating. Motors evaluated in Section 6.1 have less than 90% terminal voltage. The minimum voltage observed is 89.70% (from Table 6.1). This will cause the current to increase by 11.35% over the current at rated voltage (= 1.1135 x Motor Rated Full Load Current).

Calculation E-200, "Overcurrent Setpoints," documents the overcurrent protective device setting criteria. Per calculation E-200, the motor feeder time overcurrent elements are set as follows:

6.2.1 4160 VAC Motor Feeders:

6.2.1.1 Time-overcurrent (TOC) is set at a minimum of 1.15 x Motor Full Load Current to alarm for moderate overloads.

6.2.1.2 High-dropout instantaneous is set at a minimum of 1.65 x Motor Full Load Current to trip in conjunction with TOC element for excessive overloads.

6.2.1.3 Standard instantaneous is set at a minimum of 1.73 x Motor Full Load Current to trip for motor feeder faults.

6.2.2 480 VAC Motor Feeders:

6.2.2.1 Long time pick up is set at a minimum of 1.65 x Motor Full Load Current for overloads.

6.2.2.2 Instantaneous pick up is set at a minimum of 1.73 x Motor Full Load Current for motor feeder faults.

6.2.2.3 Instantaneous overcurrent relay with a build-in-timer connected across a CT is set at a minimum of 1.15 x Motor Full Load Current to alarm for moderate

overloads after allowing 15 seconds for motor acceleration time. For HVR-UC 1A/lB/1C this protection is modified to provide backup protection to trip the incoming feeder breaker after allowing adequate time -for motor feeder breaker to trip.

From 6.2.1 and 6.2.2, it is evident that the increase in full load current, due to decrease in available running voltage for motors will not cause the overcurrent trip to pick up for the motor feeder breakers at 70% terminal voltage for less than 60 seconds time period.

Also, standby 4160 and 480 VAC motors (non-MOV motors) are designed to carry rated load for 60 seconds at 70% of rated voltage (Section 7.1).

Review of E-200 curves shows that the safety related motors will be able to carry load at 70%

terminal voltage for 60 seconds without tripping the supply breaker. Also, at 70% terminal voltage, the current is expected to increase by 100/70 % (= 1.43%). This increase is lower than the long time pickup setting criteria of 1.65 x Motor Full Load Current for overloads and therefore, will not cause the breaker to trip.

B. Degraded Voltage Transient Analysis at Lower Analytical Limit:

B.6.1 Motor Terminal Voltages:

All motor terminal voltages are above 70% during start. The following motors are shown to have a minimum voltage less than 70%.

MOTOR Minimum Voltage During Starting Period HVR-UCIA 68.38%

H-IVR-UC 1B 68.98%

The minimum voltage observed is not during the first 1 second of the start. This minimum voltage is observed momentarily due to start of other large motors on the bus. The actual voltage at T=0 is greater than 70% and hence the motor will start when required. Attachment 12B.21 provides the summary of terminal voltage at the motors.

B.6.2 MOV Terminal Voltages:

The available voltages at all MOVs subject to GL 89-10 requirements have been provided as an input to G13.18.2.3*325. Attachment 12B.25 provides lowest possible MOV terminal voltage during a LOCA transient at the Lower Analytical Limit reset. MOV calculations developed under the GL 89-10 program

will demonstrate whether MOVs have adequate voltage. See MOV voltage tables in Attachment 12B.25 for the available voltages at all MOVs. NOTE: Attachment 12B.07 only provides MOV terminal voltage for a transient with grid voltage at 97.5%. Attachment 12B.07 shall not be used as an input for MOV calculations. Attachment 12B.07 is only for information only.

Based on input provided by the MOV calculation, the following MOVs were further evaluated for higher voltages (also see Attachment 12B.25):

E12-MOVF037B:

Based on ETAP output report 12B.25, the minimum voltage during end of stroke for E12-MOVF037B is 83.8 1%. This MOV has a max stroke time of 75 seconds. This means it is completing its stroke while voltage is artificially low (Assumption 8.3) due to MOVs that do not get an automatic start signal on a LOCA being assumed to stroke 68-70 seconds after receipt of a LOCA signal. Due to starting of a large number of MOVs at the same time, voltage on the bus drops substantially and thus reduces the MOV terminal voltage. These MOVs are only operated manually and will not be started at the same time.

Therefore, motor terminal voltage before the 70s MOV load block has been provided. MOV terminal voltage of 89.07% is provided for end of stroke. Detailed MOV voltage profile is provided in attachment 12B.23.

G33-MOVF054:

ETAP output report 12B.25 shows that the minimum voltage during end of stroke for G33-MOVF054 is 79.53%. During the allowable stroke time of the MOV, the voltage during end of stroke recovers above 84%. Therefore, 84.05% is provided for end of stroke time for G33-MOVF054. Detailed MOV voltage profile is provided in attachment 12B.22.

E22-MOVF004:

ETAP output report 12B.25 shows that the minimum voltage for E22-MOVF004 is 72.65% during start and 82.36% during end of stroke. The initial substantial drop in voltage for E22-MOVF004 is due to start of HPCS pump motor at the same time. The voltage on the MOV recovers after I second. The MOV is evaluated for terminal voltage after 1 second by placing under Locked Rotor Current for an additional 0.5 seconds. The terminal voltage on E22-MOVF004 recovers to 77% during start. The additional 0.5 seconds is within the 10 seconds LOP-LOCA analysis. During a LOP-LOCA, it is assumed that after receipt of a LOCA signal the diesel generator will pickup the 4160 VAC bus voltage within 10 seconds and will allow motors to start pumping water in the reactor after that. Thus, a 1 second delay of start of E22-MOVF004 is bounded by this analysis.

83% terminal voltage is provided for end of stroke voltage when if the MOV is required to close based on the voltage recovery during end of stroke.

Detailed MOV voltage profile is provided in attachment 12B.24.

7.0 Input and Design Criteria 7.1 Per the Voltage and Frequency Variations section of the safety related motor specifications (See G13.18.3.6*018 Attachment 1 lD.2 for specification numbers), All motors shall be capable of carrying rated load for 60 seconds at 70% of rated voltage.

7.2 Reset differential for the degraded voltage relays has been taken from calculation G13.18.3.1-004 and G13.18.3.1-005.

8.0 Assumptions See base calculation G13.18.3.6*016 for assumptions. This calculation markup does not change any assumptions.

9.0 Method of Analysis Loss of Voltage relay analysis:

The Loss of Voltage relay protection is provided to ensure that sustained degraded grid conditions under Non-LOCA scenarios do not damage the safety related equipment. The Loss of Voltage relay settings are selected to limit the magnitude and duration of an undervoltage condition on safety related buses.

The setting should be low enough to ensure that nuisance tripping does not occur from anticipated dynamic effects such as motor starting. RBS safety related motors are capable of carrying load for 60 seconds at 70% of rated voltage. The Analytical Limit for the relays is selected by calculated the 4160 VAC bus voltage such that the worst case motor has 70% terminal voltage.

The Analytical Limit for the relays is calculated by reducing the grid voltage until the worst case motor on each safety related division has _>70% terminal voltage. Attachment 12B. 17 provides the summary of voltages at safety related motors. Attachment 12B.17 also provides all the configurations, study cases and study files used for the calculation of the Analytical Limit for the Loss of Voltage relays.

A study wizard has been created in ETAP titled "LOV Analysis." This study wizard will run all scenarios listed in Attachment 12B.17.

Degraded Voltage Transient Analysis at Lower Analytical Limit:

The degraded voltage relay protection analysis at the Lower Analytical Limit is performed to show that if the relay drop out is set at the Lower Analytical Limit, the RBS motors and MOVs will have adequate voltage to perform their safety function should the grid degrade substantially below 97.5%. This analysis shows that if a LOCA occurs with the grid below 97.5% and the voltage on the bus recovers to reset the relay, the RBS motors and MOVs will have adequate voltage. To perform the analysis the following is performed:

9.1 The relay dropout is set at the Lower Analytical Limit.

9.2 Relay reset is calculated by adding relay reset differential to the Lower Analytical Limit.

9.3 Grid voltage is lowered such that during a LOCA transient the 4160 VAC bus voltage recovers above the relay reset value at the Lower Analytical Limit.

Since the grid voltage is not fixed under this methodology, an analysis is performed by lowering grid voltage for each division. For analysis of motor terminal voltages, LOCA I UAL and LOCA II UAL ETAP configurations are used. For analysis of MOV terminal voltages, LOCAI NOSWP and LOCAII NOSWP ETAP configurations have been created. During a LOCA with offsite power available it is not required to consider Standby Service Water pumps to start as the Normal Service Water pumps will be available. Associated fan loads that start with the Standby Service Water pumps have also been turned off for this analysis. These loads are detailed in attachment I ID. 15 of calculation G 13.18.3.6*018.

10.0 Available Margin This markup does not impact available margin provided in calculation G13.18.3.6*016.

11.0 Calculations A. 11. 1 Loss of Voltage Relay Lower Analytical Limit:

Based on the methodology described in Section 9.0, Load Flow runs are performed by lowering the grid voltage. Attachment 12B.17 provides the Lower Analytical Limit and equipment terminal voltages for the applicable 4160 Bus. The summary for the results is provided below in Table 11.1 and 11.2. Analytical limits for the loss of voltage relays have been selected higher than necessary to provide margin to 70% motor terminal voltage at the associated bounding component on each bus.

Table 11.1 Bus Chosen Lower Analytical Limit Corresponding Grid Voltage ENS-SWG1A 2950.00 VAC 77%

ENS-SWG1B 2950.00 VAC 73.44%

E22-S004 2935.00 VAC 76.86%

At the above analytical limits, the following loads, considered the bounding loads on each bus, are found to have the lowest steady state terminal voltage (> 70% of rated voltage):

Table 11.2 ID Bus Load Terminal Voltage

(% of Rated Voltage)

HVR-UC1A Div I 70.49 HVR-UC1B Div II 70.56 HVP-FN3A Div III 70.40 B. 11.1 Degraded Voltage Transient Analysis at Lower Analytical Limit:

The following table provides the reset voltage used for the analyses outlined in Section 9.0. For the scenarios described in this calculation, the grid voltage is set such that the 4.16kV busses are to recover to just above the minimum reset values associated with the lower analytical limit for the degraded voltage relays as described in G13.18.3.6*016 Rev 2.

Table 11.3 Minimum Voltage Bus Grid Voltage Lower Analytical Reset Differential Reset Voltage During Transient Division (% of 230 KV) Limit (VAC) (VAC) (VAC) (% ofD 160 VAC)

I 94.14 3667 18.8534 3685.8534 79.7662 II 94.00 3667 18.8534 3685.8534 81.1904 III 93.66 3650 18.935 3668.935 80.5662 The motor terminal voltages are provided in attachments 12B. 18 through 12B.21 of this calculation.

Attachment 12B.21 provides a summary of voltages at the motor terminals.

For, Division I motors, Attachment 12B. 18 voltages are used. ETAP Configuration - LOCA I UAL, Study Case - LOCA-LAL-AO1, Output Report - LOCA 1 LAL - MOTORs.

Division II motors, Attachment 12B. 19 voltages are used. ETAP Configuration - LOCA II UAL, Study Case - LOCA-LAL-BO 1, Output Report - LOCA 2 LAL - MOTORs.

Division III motors, Attachment 122B.20 voltages are used. ETAP Configuration - LOCA II UAL, Study Case - LOCA-LAL-B 01, Output Report - LOCA 3 LAL - MOTORs.

The MOV terminal voltages are provided in attachments 12B.22 through 12B.25 of this calculation.

Attachment 12B.25 provides a summary of voltages at the MOV terminals.

For, Division I MOVs, Attachment 12B.22 voltages are used. ETAP Configuration - LOCAI NOSWP, Study Case - LOCA-LAL-AO 1, Output Report - LOCA 1 LAL - MOVs.

Division II MOVs, Attachment 12B.23 voltages are used. ETAP Configuration - LOCAII NOSWP, Study Case - LOCA-LAL-B01, Output Report - LOCA 2 LAL - MOVs.

Division III MOVs, Attachment 128.24 voltages are used. ETAP Configuration - LOCAII NOSWP, Study Case - LOCA-LAL-B0I, Output Report - LOCA 3 LAL - MOVs.

12.0 Attachments 12B.14. Div I Loss of Voltage Relay Analytical Limit Load Flow Report 12B.15. Div II Loss of Voltage Relay Analytical Limit Load Flow Report 12B.16. Div III Loss of Voltage Relay Analytical Limit Load Flow Report 12B.17. Summary of results for Attachment 12B.14, 12B.15 and 12B.16 12B. 18. Div I Lower Analytical Limit analysis - motor terminal voltages 12B. 19. Div II Lower Analytical Limit analysis - motor terminal voltages 128.20. Div III Lower Analytical Limit analysis - motor terminal voltages 122B.21. Summary of motor terminal voltage results 12B.22. Div I Lower Analytical Limit analysis - MOV terminal voltages.

128.23. Div II Lower Analytical Limit analysis - MOV terminal voltages 128.24. Div III Lower Analytical Limit analysis - MOV terminal voltages 12B.25. Summary of GL 89-10 MOV Terminal Voltages at LAL Reset

ATTACHMENT 6 RBG-47193 List of Commitments RBG-47193 Page 1 of 1 Commitment One-time Continuing Schedule for Action Compliance Completion RBS setpoint calculations, and affected X Prior to end of calibration and functional test next refueling procedures, have been revised, or will be outage revised prior to implementation to reflect the new 30-month drift values.

+ 4 t -t t

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