RNP-RA/18-0044, Supplement to License Amendment Request Proposing to Add a Qualified Offsite Circuit to Technical Specification 3.8.1, AC Sources - Operating and the Use of Load Tap Changers in the Automatic Mode of Operation on the Startup Transform
| ML18192C179 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 07/11/2018 |
| From: | Kapopoulos E Duke Energy Progress |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| RNP-RA/18-0044 | |
| Download: ML18192C179 (22) | |
Text
Ernest J. Kapopoulos, Jr.
H. B. Robinson Steam Electric Plant Unit 2 Site Vice President Duke Energy 3581 West Entrance Road Hartsville, SC 29550 O: 843 951 1701 F: 843 951 1319 Ernie.Kapopoulos@duke-energy.com July 11, 2018 Serial: RNP-RA/18-0044 10 CFR 50.90 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 H.B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261 RENEWED LICENSE NO. DPR-23
SUBJECT:
SUPPLEMENT TO LICENSE AMENDMENT REQUEST PROPOSING TO ADD A QUALIFIED OFFSITE CIRCUIT TO TECHNICAL SPECIFICATION 3.8.1, AC SOURCES - OPERATING AND THE USE OF LOAD TAP CHANGERS IN THE AUTOMATIC MODE OF OPERATION ON THE STARTUP TRANSFORMERS
REFERENCES:
- 1. Duke Energy letter, License Amendment Request Proposing to Add a Qualified Offsite Circuit to Technical Specification 3.8.1, AC Sources - Operating and the Use of Load Tap Changers in the Automatic Mode of Operation on the Startup Transformers, dated September 27, 2017 (ADAMS Accession No. ML17270A041).
- 2. Nuclear Regulatory Commission email, Robinson RAIs - LAR to Revise TS to Add a 2nd Qualified Offsite Power Circuit and Revise UFSAR to Operate LTCs in Automatic Mode, dated April 18, 2018 (ADAMS Accession No. ML18108A759).
- 3. Duke Energy letter, Response to Request for Additional Information (RAI) Regarding License Amendment Request Proposing to Add a Qualified Offsite Circuit to Technical Specification 3.8.1, AC Sources - Operating and the Use of Load Tap Changers in the Automatic Mode of Operation on the Startup Transformers, dated May 16, 2018 (ADAMS Accession No. ML18137A353).
Ladies and Gentlemen:
By letter dated September 27, 2017 (Reference 1), Duke Energy Progress, LLC (Duke Energy) submitted a License Amendment Request (LAR) for H.B. Robinson Steam Electric Plant, Unit No. 2 (HBRSEP). The proposed amendment would revise Technical Specifications (TSs) to reflect the addition of a second qualified offsite power circuit. In addition, the proposed
U.S. Nuclear Regulatory Commission Serial: RNP-RA/18-0044 Page 2 amendment would revise the licensing basis to allow for the use of load tap changers (L TCs) in automatic mode on the new 230kV and replacement 115kV startup transformers.
By email dated April 18, 2018 (Reference 2), a request for additional information (RAI) was sent to Duke Energy regarding the LAR. Duke Energy's response to the RAI was provided by [[letter::RNP-RA/18-0036, Response to Request for Additional Information (RAI) Regarding Amendment Request Proposing to Add a Qualified Offsite Circuit to Technical Specification 3.8.1, AC Sources - Operating and the Use .|letter dated May 16, 2018]] (Reference 3).
Duke Energy has identified information relevant to the LAR that requires a change to the original request. Therefore, Duke Energy supplements the original request with the information in the enclosure to this letter. This supplement is a minor change to the original request and does not impact the conclusions of the no significant hazards consideration in the original submittal.
The original submittal contained a requested approval by September 15, 2018, to support implementation of the design change in HBRSEP refueling outage 31. That requested approval date has not changed; Duke Energy requests that the amendment be implemented within 90 days of approval.
In accordance with 10 CFR 50.91, "Notice for Public Comment; State Consultation," a copy of this application, with enclosure, is being provided to the designated South Carolina Officials.
If you should have any questions regarding this submittal, please contact Mr. Kevin Ellis, Manager - Regulatory Affairs, at 843-951-1329.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on July ___ I-I __, 2018.
Sincerely, Ernest J. Kapopoulos, Jr.
Site Vice President EJK/jrc
Enclosure:
SUPPLEMENT TO LICENSE AMENDMENT REQUEST PROPOSING TO ADD A QUALIFIED OFFSITE CIRCUIT TO TECHNICAL SPECIFICATION 3.8.1, "AC SOURCES-OPERATING" AND THE USE OF LOAD TAP CHANGERS IN THE AUTOMATIC MODE OF OPERATION ON THE STARTUP TRANSFORMERS
U.S. Nuclear Regulatory Commission Serial: RNP-RA/18-0044 Page 2 amendment would revise the licensing basis to allow for the use of load tap changers (LTCs) in automatic mode on the new 230kV and replacement 115kV startup transformers.
By email dated April 18, 2018 (Reference 2), a request for additional information (RAI) was sent to Duke Energy regarding the LAR. Duke Energys response to the RAI was provided by [[letter::RNP-RA/18-0036, Response to Request for Additional Information (RAI) Regarding Amendment Request Proposing to Add a Qualified Offsite Circuit to Technical Specification 3.8.1, AC Sources - Operating and the Use .|letter dated May 16, 2018]] (Reference 3).
Duke Energy has identified information relevant to the LAR that requires a change to the original request. Therefore, Duke Energy supplements the original request with the information in the enclosure to this letter. This supplement is a minor change to the original request and does not impact the conclusions of the no significant hazards consideration in the original submittal.
The original submittal contained a requested approval by September 15, 2018, to support implementation of the design change in HBRSEP refueling outage 31. That requested approval date has not changed; Duke Energy requests that the amendment be implemented within 90 days of approval.
In accordance with 10 CFR 50.91, Notice for Public Comment; State Consultation, a copy of this application, with enclosure, is being provided to the designated South Carolina Officials.
If you should have any questions regarding this submittal, please contact Mr. Kevin Ellis, Manager - Regulatory Affairs, at 843-951-1329.
I declare under penalty of perjury that the foregoing is true and correct.
Executed on July _______, 2018.
Sincerely, Ernest J. Kapopoulos, Jr.
Site Vice President EJK/jrc
Enclosure:
SUPPLEMENT TO LICENSE AMENDMENT REQUEST PROPOSING TO ADD A QUALIFIED OFFSITE CIRCUIT TO TECHNICAL SPECIFICATION 3.8.1, AC SOURCES - OPERATING AND THE USE OF LOAD TAP CHANGERS IN THE AUTOMATIC MODE OF OPERATION ON THE STARTUP TRANSFORMERS
U.S. Nuclear Regulatory Commission Serial: RNP-RA/18-0044 Page 3 cc (with Enclosure):
C. Haney, NRC Region II - Regional Administrator J. Rotton, NRC Senior Resident Inspector - RNP D. Galvin, NRR Project Manager - RNP S. E. Jenkins, Chief, Bureau of Radiological Health (SC)
A. Wilson, Attorney General (SC)
U.S. Nuclear Regulatory Commission Serial: RNP-RA/18-0044 Enclosure ENCLOSURE SUPPLEMENT TO LICENSE AMENDMENT REQUEST PROPOSING TO ADD A QUALIFIED OFFSITE CIRCUIT TO TECHNICAL SPECIFICATION 3.8.1, AC SOURCES - OPERATING AND THE USE OF LOAD TAP CHANGERS IN THE AUTOMATIC MODE OF OPERATION ON THE STARTUP TRANSFORMERS H.B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 (HBRSEP)
DOCKET NO. 50-261 RENEWED LICENSE NO. DPR-23
U.S. Nuclear Regulatory Commission Enclosure to Serial: RNP-RA/18-0044 Page 2 Supplement By letter dated September 27, 2017 (ADAMS Accession No. ML17270A041), Duke Energy Progress, LLC (Duke Energy) submitted a License Amendment Request (LAR or original request) for H.B. Robinson Steam Electric Plant, Unit No. 2 (HBRSEP). The proposed amendment would revise Technical Specifications (TSs) to reflect the addition of a second qualified offsite power circuit. In addition, the proposed amendment would revise the licensing basis to allow for the use of load tap changers (LTCs) in automatic mode on the new 230kV and replacement 115kV startup transformers (SUTs).
By email dated April 18, 2018 (ADAMS Accession No. ML18108A759), a Request for Additional Information (RAI) was sent to Duke Energy regarding the original application. Duke Energys response to the RAI was provided by [[letter::RNP-RA/18-0036, Response to Request for Additional Information (RAI) Regarding Amendment Request Proposing to Add a Qualified Offsite Circuit to Technical Specification 3.8.1, AC Sources - Operating and the Use .|letter dated May 16, 2018]] (ADAMS Accession No. ML18137A353).
Duke Energy has identified information relevant to the LAR that requires a change to the original request. Therefore, Duke Energy supplements the original request with the information in this enclosure. This supplement is a minor change to the original request and does not impact the conclusions of the no significant hazards consideration in the original submittal.
The markups to the original LAR are provided in the attachment to this enclosure.
Change 1. Revise TS Surveillance Requirement (SR) 3.8.1.16 Current SR 3.8.1.16 Note 2. SR 3.8.1.16 is not required to be met if 4.160 kV bus 2 and 480 V Emergency Bus 1 power supply is from the start up transformer.
Verify automatic transfer capability of the 4.160 kV bus 2 and the 480 V Emergency bus 1 loads from the Unit auxiliary transformer to the start up transformer.
Proposed change:
Note 2. SR 3.8.1.16 is not required to be met if 4.160 kV bus 2 and 480V Emergency Bus 1 power supply is from a start up transformer.
Verify automatic transfer capability of the 4.160 kV bus 2 and the 480V Emergency bus 1 loads from the Unit auxiliary transformer to a start up transformer.
The safety function tested by SR 3.8.1.16 is the transfer of the 4.160kV bus 2 power supply from the auxiliary transformer to the SUT, which demonstrates the operability of the offsite circuit network to power the shutdown loads. The function tested is downstream from the intermediate busses powered by either of the two SUTs and can be tested completely with either SUT.
The proposed change from the word the to the word a is administrative in nature and has no impact on the transfer function addressed by the SR. The change only reflects that the function
U.S. Nuclear Regulatory Commission Enclosure to Serial: RNP-RA/18-0044 Page 3 being tested can be accomplished with either the new 230kV start up transformer or the new 115kV start up transformer. TS Bases will also be revised to reflect this change, but approval of the Bases is not requested.
Change 2. Revise TS SR 3.8.1.18 frequency from 18 to 24 months The LAR proposed new TS SR 3.8.1.18 to verify manual transfer of AC power sources from the normal offsite circuit to each alternate offsite circuit, which aligns HBRSEP TSs to guidance in NUREG 1431, Revision 4. The 18-month frequency of the SR was based on engineering judgment, taking into consideration the unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. On May 25, 2018, the NRC issued HBRSEP Operating License Amendment 258 (ADAMS Accession No. ML18115A150), which revised other TS SR frequencies to support 24-month fuel cycles. Consequently, Duke Energy revises the request to change SR 3.8.1.18 frequency from 18 to 24 months, based on engineering judgment, taking into consideration the unit conditions required to perform the Surveillance, and to support operation with 24-month fuel cycles. TS Bases will also be revised to reflect this change, but approval of the Bases is not requested.
Change 3. Section 3.2.1 Figure 1, 115/230kV Startup Transformers Control and Limit Bands Figure 1, 115/230kV Startup Transformers Control and Limit Bands, is replaced with an updated figure. This change reflects the evolution of the design that impacted the numeric values shown. The figure has been revised to remove the values associated with the uncertainty bands and upper and lower limits for the controllers. The Updated Final Safety Analysis Report figure, also included in the attachment, has been revised to include the updated numerical values.
Change 4. Sections 3.2.3, 3.3.3.4, & 3.3.3.6 Regarding Manual Operation of the LTC As stated in Section 3.2.1 of the LAR, operation of the LTCs for the 115kV and 230kV SUTs in the manual mode has been evaluated in accordance with 10 CFR 50.59 and was not submitted for NRC approval. The LAR provided information and figures demonstrating automatic LTC operation, but also included a discussion related to the LTC in manual mode. As calculations evolved following submittal of the LAR, some of the details discussed in the LAR regarding manual operation changed.
Section 3.2.3 discusses the condition with the automatic LTC not functional and LTCs in manual. The operational strategy for LTCs in manual has evolved, so the description in the LAR was revised to accurately describe the evolved strategy; however, NRC approval is not requested for LTCs in manual.
As stated in Section 3.3.3 of the LAR, transient voltage analysis was performed to ensure that during large motor starts, plant transients and grid transients, the plant equipment has sufficient voltage to ride through and remain running following the transient. In addition, analysis was performed to show that the revised HBRSEP transmission system can react to the worst-case grid transients without timing out the E1/E2 DGVR (degraded grid voltage relays) and Loss of Voltage (LVR) relays.
U.S. Nuclear Regulatory Commission Enclosure to Serial: RNP-RA/18-0044 Page 4 Sections 3.3.3.4 through 3.3.3.6 provided insights and results of transient load flow analyses with LTCs in both automatic and manual control. The analysis that supported the original submittal concluded a fixed transformer tap setting would provide satisfactory results, but the approach did not provide sufficient flexibility for operations, so the strategy evolved to prescribe various manual tap changer positions corresponding to offsite power conditions.
Although operation in manual was not and is not submitted for NRC approval, revisions were made to the text in sections 3.2.3, 3.3.3.4, and 3.3.3.6 to align the text with the conclusions of the current analyses.
Change 5. Section 3.3.2.2 Table 4 Tabulation - Transformer Loading and Margin The values in this section were originally taken from configurations N5 and N6. N6 was later eliminated as a valid operating configuration, however, this section was not revised to reflect that change. In addition, the values for N5 were incorrectly listed in the LAR. This revision corrects the table and text in the first paragraph to reflect the current analysis. This section also contained a statement that the equipment load is not changed by the addition of the offsite power source. This statement did not consider the addition of transformer auxiliary loads and other minor changes, and therefore, this sentence is removed as it is not required information for approval. Lastly, the final sentence implied that the margin increased for both the 230kV SUT and 115kV SUT. The 230kV SUT is a new component, so a change in margin on a new component is no longer discussed.
Change 6. Sections 3.3.3.1, 3.3.3.2, and 3.3.3.7 DGVR Setpoint Input The original submittal stated the analysis used the maximum degraded relay setpoint of 433V to evaluate DGVR pickup. The calculation used 437V, the setpoint adjusted for instrument uncertainty. Consideration of uncertainty results in a more restrictive acceptance criterion and is the appropriate approach for the analysis. It should be noted that this value should not be confused with the TS dropout value of 430V +/- 4V.
The original submittal stated that the analysis used a loss of voltage relay pickup of 352V. Duke Energy calculation RNP-E-8.066 was developed using the methodology contained in RNP-E-8.002 using the TS limit of 328 +10% (360.8V) as its limit. Therefore section 3.3.3.1 is updated to reflect the 360.8V TS value.
Change 7. Section 3.3.3.4 Transient Response Studies The LAR used a specific scenario N3 and provided graphs for that scenario in the analysis. As noted in the LAR, the figures were included for illustrative purposes. The results of N3 have changed since the original submittal, however, they still serve the same function as an illustrative reference. The text is clarified to indicate these figures represent an example study, rather than a direct reference to N3.
U.S. Nuclear Regulatory Commission Enclosure to Serial: RNP-RA/18-0044 Page 5 Change 8. RAI Response #1 Update By email dated April 18, 2018 (ADAMS Accession No. ML18108A759), a Request for Additional Information (RAI) was sent to Duke Energy regarding the original application. Duke Energys response to the RAI was provided by [[letter::RNP-RA/18-0036, Response to Request for Additional Information (RAI) Regarding Amendment Request Proposing to Add a Qualified Offsite Circuit to Technical Specification 3.8.1, AC Sources - Operating and the Use .|letter dated May 16, 2018]] (ADAMS Accession No. ML18137A353). RAI Question 1 requested a list of the calculations/analyses supporting the (Grid Stability Study), Steady State and Transient Load Flow Summaries/analysis, and Short Circuit Analysis (i.e., Fault Analysis) in Section 3.3 of the LAR, including document number, title, and revision number. Duke Energys response stated Calculation RNP-E-8.066, "RNP-E-8.002 Interim", Revision 0 (draft) supports the proposed modifications and includes the Grid Stability Study, Steady State and Transient Load Flow Summaries/Analysis, and Short Circuit Analysis (i.e., Fault Analysis). Since the submittal of the RAI response, Calculation RNP-E-8.066 has been completed as Revision 0.
U.S. Nuclear Regulatory Commission Serial: RNP-RA/18-0044 Enclosure SUPPLEMENT TO LICENSE AMENDMENT REQUEST REGARDING REVISION TO TECHNICAL SPECIFICATION 3.8.1 AND ADDITION OF A SECOND QUALIFIED OFFSITE CIRCUIT WITH NEW STARTUP TRANSFORMERS AND LOAD TAP CHANGERS IN AUTOMATIC MODE H.B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 (HBRSEP)
DOCKET NO. 50-261 RENEWED LICENSE NO. DPR-23 Attachment Technical Specification Page Markups and LAR Revisions 12 pages plus cover
AC Sources-Operating 3.8.1 HBRSEP Unit No. 2 3.8-12 Amendment No. 176 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.8.1.15 (continued)
- 5. supplies permanently connected and auto connected emergency loads for 5 minutes.
SR 3.8.1.16
NOTE------------------------------------
- 1. This Surveillance shall not be performed in MODE 1 or 2.
- 2. SR 3.8.1.16 is not required to be met if 4.160 kV bus 2 and 480 V Emergency Bus 1 power supply is from the start up transformer.
Verify automatic transfer capability of the 4.160 kV bus 2 and the 480 V Emergency bus 1 loads from the Unit auxiliary transformer to the start up transformer.
18 months SR 3.8.1.17
NOTE-------------------------------------
All DG starts may be preceded by an engine prelube period.
Verify when started simultaneously from standby condition, each DG achieves, in 10 seconds, voltage 467 V and frequency 58.8 Hz, and after steady state conditions are reached, maintains voltage 467 V and 493 V and frequency 58.8 Hz and 61.2 Hz.
10 years SR 3.8.1.18
NOTE-------------------------------------
This Surveillance shall not be performed in MODE 1 or
- 2.
Verify manual transfer of AC power sources from the normal offsite circuit to each alternate offsite circuit.
18 months a
24 Change 1 Change 2
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 12 Table 2: Backup Controller Setpoints The voltage control bands established with the above settings is shown in Figure 1 below.
Figure 1 represents the startup transformers (115kV or 230kV) LTC voltage and control limits with the switchyard voltage within the voltage schedule. Explanation of these voltage bands is provided in the subsequent descriptions of LTC operation.
Figure 1: 115/230kV Startup Transformers Control and Limit Bands The Reinhausen RMV-II tap changer mechanism for each LTC is located in a separate enclosure mounted to the transformer tanks. A drive motor rotates the tap changer to increase or decrease the number of transformer windings in service. By operating the drive motor, which changes the tap settings, the transformer output voltage is raised or lowered. The tap changer has four modes of operation: automatic, remote manual operation (uses the drive motor), local
3628V4KVBus8/9LowTransientCriteria(UpperLimit)
VoltageLimit Band(Backup Controller)
VoltageControlBand (PrimaryController) 4290OvervoltageLimit(BackupController-BlockRaiseLimit) 4400VMaximumAllowableLoadVoltage 4224UpperBandLimit 4097LowerBandLimit 4030UndervoltageLimit(BackupController-BlockLowerLimit) 4325Overvoltagerunback(BackupController-IssueLTC LowerCommand)
Nominal4160V 4074 3986 4246 4369 4240 4080 4205 4115 Change 3 UFSAR Figure
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 28 3.2.3 Evaluation of Offsite Circuit Operability with a Non-Functional Load Tap Changer Implementation of automatic operation of the LTCs will allow them to automatically compensate for variations in switchyard voltage that could otherwise render the offsite circuits inoperable. A review of plant electrical bus alignments was conducted for both normal and accident grid transients and fast bus transfers. This evaluation applied the worst case transient voltage acceptance criteria from the existing HBRSEP Load Flow and Short Circuit ETAP model calculation. The evaluation determined that the new replacement 115kV startup transformer and the new 230kV startup transformer with LTCs were able to provide the transient response necessary to prevent operation of the safety related buses E1 and E2 DGVR relay. In the event that the LTC is non-functional and unable to compensate for switchyard voltage variations, offsite circuit operability will be determined based upon the LTC position and the current switchyard voltage. The analysis established acceptable tap settings for the range of expected switchyard voltages provided in the voltage schedule. Procedures will direct the control of the LTC position to ensure the switchyard voltage and tap settings remain with the limits determined by analysis.
3.2.4 Conclusion Implementation of the automatic LTC operation will provide additional assurance that the voltage provided by the transmission system is adequate to maintain operability of the offsite power sources for the HBRSEP for the expected range of switchyard voltages. LTCs have been shown to be reliable, and the likelihood and consequences of each LTC failure mode has been evaluated and determined to be acceptable. Thus, the proposed change to operate the LTCs in the automatic mode of operation will increase overall reliability of the offsite power sources at HBRSEP.
3.3 Additional Technical Information to Support Proposed Change At a pre-application meeting between Duke Energy and the NRC staff in August 2015, the staff requested that the following information be submitted for the proposed change to install a new 230kV startup transformer and also to allow LTCs in the automatic mode of operation on the replacement 115kV startup transformer and 230kV startup transformer:
Grid Voltage Profile Summary (i.e., Grid Stability Study)
Steady State and Transient Load Flow Summaries Short Circuit Analysis (i.e., Fault Analysis) Summary Demonstration of breaker coordination of new switchgear including coordination with existing switchgear.
The following subsections provide a technical discussion on the bulleted items above.
3.3.1 Grid Voltage Profile Summary
=
Background===
HBRSEP connects to the Duke Energy Progress (Duke Energy) transmission system via a 230kV/115kV switchyard as show in Figure 2 below. There is currently a single startup transformer (SUT) connected to the 115kV part of this switchyard. As previously discussed in
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 35 Capacity of SUTs and Power Circuits to 4.16kV Buses Table 4 Tabulation - Transformer Loading and Margin Power Source Transformer Ratings (MVA)
Maximum Calculated Load (MVA)
% of Max 65 deg C Rating Margin, %
115kV SUT (existing) 44/49.28 MVA; FOA 55 deg C/ FOA 65 deg C 41.12 83.4 16.6 115kV SUT (replacement) 27/36/45 MVA 55 deg C; ONAN/ONAF1/ONAF2 50.4 MVA ONAF2 65 deg C 22.16 44.0 56.0 230kV SUT 27/36/45 MVA 55 deg C; ONAN/ONAF1/ONAF2 50.4 MVA ONAF2 65 deg C 46.65 92.6 7.4 The existing 115kV SUT load is from a HBRSEP calculation. Loading for the 115kV SUT and 230kV SUT are from ETAP model load flow cases. Transformer capacity is evaluated based on the most limiting load flow cases.
Each of the two windings on the new replacement 115kV SUT and the new 230kV SUT will deliver power via 4000A rated circuits and 4000A disconnect switches to respective 4.16kV buses served.
The new replacement 115kV SUT and the new 230kV SUT have capacity to serve HBRSEP plant loads with adequate margin.
Short Circuit A review of the normal alignments short circuit momentary duty ratings from the short circuit studies in ETAP revealed the following:
In alignments SC14, SCN5N7A, SCN6N7A and SC18, the momentary duty rating of the E1 switchgear was exceeded. These alignments are the bus alignments with the plant shutdown with EDG A or EDG B testing in progress.
In alignments SC15, SCN5N7B, SCN6N7B and SC19, the momentary duty rating of the E2 switchgear was exceeded. These alignments are the bus alignments with the plant shutdown with EDG A or EDG B testing in progress.
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 38 3.3.3.1 Acceptance Criteria The analyses that were performed used the minimum scheduled switchyard voltages (1.0086 per unit; 116kV and 232kV) discussed in Section 3.3.1 above. From the existing HBRSEP ETAP model calculation, the minimum motor start/ride through voltage of 3033.5V (73% of 4160V) was used for the acceptance criteria for the minimum transient voltage during each of the plant starts. This ensures other motors on the 4kV buses have sufficient voltage to continue running during and after the transient.
In addition to the minimum ride through transient voltage, it is also necessary to ensure the 4kV bus undervoltage relays on Buses 1, 2 and 4 do not pick-up on a reactor coolant pump (RCP) start. The worst case pickup value of 66.9% with the shortest time delay of 0.692 seconds was used as the acceptance criteria based on a HBRSEP procedure.
For the E1/E2 buses, the maximum DGVR pickup voltage, adjusted for instrument uncertainty, of 437V (91.04% of 480V) for the minimum relay time of 9.5 seconds, was used as the acceptance criteria. The DGVR pickup voltage is the voltage to which bus voltage must recover after the DGVR Trip Setpoint (430V +/- 4V) is reached to stop the timer and reset the DGVR.
No change is made to the TS degraded voltage Trip Setpoint or time delay.
Additionally, for the E1/E2 buses, the maximum Loss of Voltage relay pickup voltage of 360.8V (75.2% of 480V) for a minimum relay time delay of 0.712 seconds was used as the acceptance criteria. The value of 360.8 is chosen as the upper end of the allowable range (328V +/-10%)
defined in TS Section 3.3.5.2. No change is made to the TS loss of voltage Trip Setpoint or time delay.
3.3.3.2 Bus Transients - Pump Starts HBRSEP performed analysis to ensure a worst case pump start does not result in unacceptable voltage levels at the E1/E2 or 4kV bus levels. The worst case pump start is considered a RCP start due to it providing the largest starting transient for the longest duration. ETAP study cases were established performing pump starts in the different operating and shutdown bus alignments and evaluating the effects on the bus voltages. There were no cases where the 4kV buses fell below the 73% criterion during any RCP starts. The lowest transient voltage level on the 4kV buses for any RCP start was approximately 80%. The minimum transient value of 80%
is well above the 66.9% 4kV bus undervoltage relay setpoint.
For the E1/E2 buses, when in bus alignments N1 and N4, the voltage excursion during a RCP start did not fall below the 91.04%. Therefore, while operating in these bus alignments, it is not necessary to disable the DGVR relay during a RCP start.
However, during bus alignments N2, N3 and N5, the voltage excursions did fall below the 91.04%. Therefore, while operating in these bus alignments, it is necessary to disable the DGVR relay during a RCP start, as already required in the existing plant configuration.
In all bus alignments the E1/E2 bus voltage excursion during any RCP start was well above the 73.3% 480V bus Loss of Voltage relay setpoint and is acceptable.
During bus alignment N5, while starting a RCP with the LTC in automatic position, resulted in an undesirable bus overvoltage condition of approximately 112% due to the LTC overshooting the
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 39 setpoint. In this bus alignment, the LTC will be placed in the manual position during a RCP start.
During bus alignments N5N7 and N6N7 the LTC will be placed in the manual position during a RCP start.
During bus alignments N5N7, N6N7 and B2 the DGVR relay will be disabled during an RCP start.
3.3.3.3 Grid Transient - Development Analysis showed that the worst case grid excursion occurs when the HBRSEP unit trips. The bounding voltage profile is shown in Figure 3 above. The ETAP Transient Stability Module was utilized to create a study case defining this worst case grid excursion. Specific grid voltage magnitudes with respect to time were set, providing the ability to closely mimic the grid transient profile. The study case grid profile was used to model the system transient responses that are discussed in the following sections.
3.3.3.4 Grid Transient Response - LOCA 100% Power Bus Alignments Transient Stability Analyses were performed for plant 100% power alignments (N1, N2, N3, N4 and N5). Multiple cases were evaluated for each bus 100% power alignment analysis. One case was with the LTC in the automatic position. Other cases were evaluated with the LTC in the manual position and locked at the appropriate setting for a given switchyard voltage.
Analyses performed with the LTC in automatic position used an initial time delay of half a second and operating time delay of two seconds.
The transient response runs performed while the LTC was in the manual position were conducted to determine if there was a fixed tap position for a given switchyard voltage that provides a voltage response that meets the acceptance criteria without crediting the LTC response time.
For each of the transient runs, the transient started at T = 1 second, followed by LOCA bus load sequencing and finally a fast bus transfer of loads from the UAT to the respective SUT at T = 61 seconds.
The first set of analyses that was conducted provided voltage amplitude plots versus time in order to show conformance with the acceptance criteria for E1/E2 bus voltage DGVR response and also 4kV Buses 1, 2 and 4 bus undervoltage relay response.
The second set of analyses that was conducted provided motor ampacity plots versus time for the 4kV motors and E1/E2 bus motors 150HP and larger. The ETAP model was updated to include each 4kV motor and E1/E2 bus motor 150HP and larger ANSI protective 50/51 device settings. The analyses demonstrated that each motors ampacity excursion during the transient is not of sufficient duration that results in tripping its respective overcurrent protective relay.
For illustrative purposes, the results of an example study with the SUT LTC in the automatic position is shown on the following three graphs (Figures 4, 5 and 6). These graphs reflect the system responses and demonstrate compliance with the acceptance criteria.
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 40 Figure 4 demonstrates Buses E1/E2 voltage excursions did not result in the DGVR timing out during the system response shown for the example study. Figure 4 also demonstrates that no voltage excursion resulted in the voltage falling below the maximum DGVR time delay pick-up value greater than the relays 9.5 seconds time delay. Additionally, the E1/E2 bus voltage excursion did not approach the Loss of Voltage relay pickup value of 73.33% and is therefore acceptable.
Figure 4
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 41 Figure 5 demonstrates that during the example study, the voltage on the 4kV Buses 1, 2 and 4 dropped below the undervoltage relays setpoint for no more than 0.1 seconds. Since the 4kV Buses 1, 2 and 4 undervoltage relays have a time delay setting of 0.692 seconds, which is greater than 0.1 seconds, the 4kV Bus 1, 2 and 4 undervoltage relays did not pick-up during this grid transient condition and is acceptable.
Figure 5
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 42 Figure 6 demonstrates that the 4kV motors and Bus E1/E2 motors 150HP and greater remained running and did not stall or trip based on their respective instantaneous and/or time overcurrent trip settings during the example study.
Figure 6 In 100% power bus alignments N1, N2, N4 and N5 with the SUT LTC in the automatic position, the analyses demonstrated similar acceptable system results as described above for the example study.
In 100% power bus alignments N1 and N4, operation with the LTC in the manual position and locked at the appropriate tap setting for a given switchyard voltage, the analysis demonstrated similar acceptable system results as described above.
However, in 100% power bus alignments N2, N3 and N5 operation with the LTC locked in
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 43 manual resulted in the Bus E1/E2 bus voltage excursion timing out the DGVR and subsequent transfer to the onsite emergency power source. The 4kV Buses 1, 2 and 4 undervoltage relays did not time out and the 4kV motors remained running.
3.3.3.5 Grid Transient Response - LOCA with Plant in Backfeed One Transient Stability Analysis was performed for the B2 backfeed alignment with a LOCA (Safety Injection). The worst case grid transient was not used for this evaluation since the plant is shutdown and the plant trip transient is not applicable. The worst case grid voltage of 226kV was assumed to be present in the 230kV Switchyard and was used for ETAP modeling purposes.
For this LOCA transient run, the transient started at T = 1 second, followed by LOCA bus load sequencing. Note that some loads such as the Service Water (SW) Pump and SW Booster Pump are already running in this plant shutdown alignment.
In the B2 alignment, the LOCA transient did not result in the Bus E1/E2 bus voltage excursion timing out the DGVR. The 4kV Buses 1, 2 and 4 undervoltage relays did not time out and the Bus E1/E2 motors 150HP and greater remained running during and after the transient.
3.3.3.6 Grid Transient - Plant Trip with Fast Bus Transfers This analysis covered plant trips where the fast bus transfer occurs immediately, and also where it occurred after 60 seconds. Plant trips resulting from a generator lockout initiate an immediate fast bus transfer and plant trips resulting from a Safety Injection (SI) signal result in fast bus transfers at T = 60 seconds.
Transient Stability Analyses were performed for plant 100% power alignments (N1, N2, N3, N4 and N5). Multiple cases were analyzed for each bus alignment. One case was with the LTC in the automatic position. Other cases were evaluated with the LTC in the manual position and locked at the appropriate setting for a given switchyard voltage. The analyses performed with the LTC in automatic position used an initial time delay of half a second and an operating time delay of two seconds.
The 100% power bus alignments N1 and N4 with the SUTs LTC in the manual position and locked at the appropriate setting for a given switchyard voltage provided acceptable system response.
However, the 100% power bus alignments N2, N3 and N5 with the SUTs LTC in the manual position and locked at the appropriate setting for a given switchyard voltage resulted in the Bus E1/E2 bus voltage excursion timing out the DGVR and subsequent transfer to the onsite emergency power source. The 4kV Buses 1, 2 and 4 undervoltage relays did not time out and the 4kV motors remained running.
3.3.3.7 Conclusions For the 480V emergency buses E1 and E2, when in bus alignments N1 and N4, the voltage excursion during a RCP start does not fall below the maximum DGVR pickup voltage of 437V.
U.S. Nuclear Regulatory Commission RNP-RA/17-0037 - Supplement Page 44 Therefore, while operating in these bus alignments, it is not necessary to disable the DGVR relaying during a RCP start.
However, in bus alignments N2, N3, and N5, the voltage excursions do fall below the maximum DGVR pickup voltage of 437V. Therefore, while operating in these bus alignments, it is necessary to disable the DGVR relay during a RCP start as already required in the existing plant configuration.
In all bus alignments, the 480V emergency bus E1 and E2 voltage excursion during any RCP start is well above the loss of voltage relay setpoint and is acceptable.
In bus alignment N5, starting a RCP with the LTC in automatic position results in a bus overvoltage condition due to the LTC overshooting the setpoint. In bus alignment N5, the LTC will be placed in the manual position during a RCP start.
In bus alignment N7, voltages are capable of being maintained at emergency buses E1 and E2 during a LOCA.
During bus alignments N5N7 and N6N7, the LTC will be placed in the manual position during a RCP start.
During bus alignments N5N7, N6N7 and B2, it is necessary to disable the DGVR relay during a RCP start.
3.3.4 Breaker Coordination and Equipment Protection Summary The HBRSEP design basis states the following with respect to overcurrent protection and coordination:
The off-site power system should be provided with protective devices for overload and short circuit protection and to minimize, through relay coordination, the effects of faults upon the balance of the system.
In order to demonstrate compliance with above design basis requirement with the new transmission upgrades installed, a summary of the breaker coordination and protection relaying findings from an HBRSEP evaluation is provided below.
3.3.4.1 Evaluation of HBRSEP to Transmission Engineering Resource and Project Management (TERPM) Relay Coordination HBRSEP performed analysis to demonstrate that the Transmission Engineering Resource and Project Management (TERPM) SUT high and low 487E protective relay setpoints will provide for coordination with downstream plant relaying to ensure additional relay interlocking is not necessary. Coordination with downstream plant relaying ensures the following:
- 1. Coordination between the furthest upstream HBRSEP 4kV Bus 6-9 breaker relaying and the TERPM high and low side transformer relaying.