DPP February 2015 South System Impact Study Report 09/26/2016

Transcription

1 DPP February 205 South System Impact Study Report 09/26/206 Prepared by Resource Interconnection and Planning Midcontinent Independent System Operator Lakeway Two 3850 N. Causeway Blvd. Suite 442 Metairie, LA 70002

2 Table of Contents. Executive Summary Adhoc Group Details Model Development and Study Assumptions... 4 A. Base Case Models... 4 B. Monitored Elements... 4 C. Contingencies... 5 D. Study Methodology... 6 E. Performance Criteria Thermal Analysis Results Voltage Analysis Results Stability Analysis Short Circuit Analysis Deliverability Study Shared Network Upgrades Impact on ANO thermal limits Affected System Analysis HIS /SSTI (Harmonic Impedance Scanning /Sub-synchronous Torsional Interaction) study... 8 Appendix... 9 Appendix A Stability Analysis Reports... 9 Appendix B SPP Affected System Study... 9 Appendix C HIS /SSTI (Harmonic Impedance Scanning /Sub-synchronous Torsional Interaction) study.. 9 Table Project Details... 3 Table 2 Monitored Elements

3 . Executive Summary This report provides study analyses performed to determine the transmission improvements required to reliably interconnect the generation projects in the DPP February South group to the transmission system. Detail regarding the project and corresponding analysis is shown in Table. Table Project Details Project Number Interconnecting TO POI County State Fuel Service Requested MW In Service date ERIS Study (Thermal, Stability, Short Circuit) NRIS Study / Deliverability Analysis J39 Entergy Tapping ANO- Pleasant Hill 500 kv line Pope AR HVDC ERIS and NRIS 500 //208 Yes Note: J39 being an HVDC injection, NRIS is not applicable Note: J47 which was in DPP February South group had withdrawn and it was determined that additional analysis was not necessary to evaluate its impact on the ongoing analysis, as its POI being in LA was remote with respect to J39. Steady state analysis indicated that J39 has no adverse impact on the system for system intact and N- contingency conditions. However, for prior outage of J39 Tap Pleasant Hill J39 would be backed down to 0 to respect the thermal rating of ANO Xmer; so as to prepare for the 2nd contingency (B506 STK ); during which ANO Xmer would be the only outlet for ANO units as well as J39. Currently ANO units are being backed down to respect ANO Xmer for this scenario; which indicates there is no additional injection available for J39. An operating guide would be considered for backing down and an SPS would not be considered for the same. Service Agreement will be documenting the details pertaining to backing down J39 to 0 for the concerned scenario and that the back down procedure is contingent on the operating guide. Stability analysis for J39 performed by ABB, showed that study project did not adversely impact the system for normally cleared faults and stuck breaker faults with back up clearing. However, additional stability analysis performed to study impact of J39 on ANO established stability limits showed that J39 adversely impacts ANO transient stability limits for two scenarios involving prior outage of J39 Pleasant Hill 500 kv line followed by SLG stuck breaker fault (B506 STK) at ANO bus. The post-fault configuration is such that Project J39 is radially connected into the ANO 500 kv bus and there is only one transmission outlet out of this bus (ANO 500/6 kv transformer) that is forced to carry the full output of the ANO plant (at its established stability limit), plus the injection from Project J39. Results show that for the concerned scenarios, it may be possible for Project J39 to inject a certain amount of B506 STK contingency takes out two 500 kv lines ANO- Ft. Smith and ANO Mabelvale 3

4 power into the grid. However, considering that the thermal rating of the ANO 500/6 kv autotransformer is more limiting for these two events, MISO and Entergy concluded that J39 needs to back down to zero (0) MW after the prior outage of J39 Pleasant Hill 500 kv line in order to reduce the flow below the thermal limits of the ANO 500/6 kv auto-transformer. Thus maximum allowable injections as derived in additional stability analysis are moot because J39 will be required to back down to 0 MW following the prior-outage of the J39 Tap Pleasant Hill 500 kv line based on thermal considerations i.e., emergency rating of the ANO 500/6 kv auto-transformer. HIS /SSTI (Harmonic Impedance Scanning and Sub-synchronous Torsional Interaction study) results / plots provides the J39 Interconnection Customer for use in their filter design calculations and convertors in the HVDC detailed design phase. Note: ) Details pertaining to upgrades/ costs/ execution plan for interconnection of the generating facility at the POI will be documented in the Facility Study for Interconnecting Generator (phase ) 2) Facilities that have been included as base case assumptions and the level of interconnection service that would be conditional upon these facilities being in service will be documented in the Service Agreement. 3) Analysis performed shows there are no projects for Shared Network Upgrade cost allocation. 2. Adhoc Group Details The Ad-Hoc group for the DPP February 205 South consisted of Entergy, Cleco, AECC, Ameren, SPP and the interconnecting customers of project J39. The group reviewed the models, assumptions, and results and provided input during the course of the study. 3. Model Development and Study Assumptions A. Base Case Models The following summer peak and shoulder /summer off peak 208 and 2025 models were used for the study. These models were derived from the DPP August 204 models by applying appropriate MTEP A projects Summer Peak and Shoulder /Summer off peak -Bench and Study cases Summer Peak and Shoulder /Summer off peak -Bench and Study cases Benchmark cases were created without generating facilities in the DPP February 205 South group. Study cases were created by adding generating facilities in the DPP February 205 South group. B. Monitored Elements The study areas defined in Table 2 were monitored in the analysis. Facilities in the study areas were monitored for system intact NERC category A conditions (system intact), and contingency conditions NERC category B & NERC Category C conditions. Under NERC category A conditions (system intact) 4

5 branches were monitored for loading above the normal (PSSE Rating A) and for NERC category B and C conditions, branches were monitored for emergency (PSSE Rating B). (EES, EAI and EMI use emergency ratings as normal ratings). Bus voltages were monitored per the limits as shown in Table 2. Table 2 Monitored Elements Area/ Owner Monitored Facilities Voltage Limits Pre-Disturbance Post-Disturbance 327 / EES & EES-EAI 69 kv and above 0.95/ / / EES & EES-EMI 69 kv and above 0.95/ / /LAGN 69 kv to 300 kv 0.95/ / /SMEPA 69 kv and above 0.95/ / /CLECO 69 kv and above 0.95/ /. 503 /LAFA 69 kv and above 0.95/ / /LEPA 69 kv and above 0.95/ / /AECI 69 kv and above 0.95/ / /CWLD 69 kv and above 0.95/ /. 356 /AMMO 69 kv and above 0.95/ /. 357 /AMIL 69 kv and above 0.95/ /. 346/SOCO 69 kv and above 0.95/ / /TVA 69 kv and above 0.95/ / /PS 69 kv and above 0.95/ /.05 55/SPP-SWPA 69 kv and above 0.95/ / /SPP-AEPW 69 kv and above 0.95/ / /SPP-OKGE 69 kv and above 0.95/ / /SPP-EMDE 69 kv and above 0.95/ /.05 C. Contingencies A variety of contingencies were considered for steady state analysis:. NERC category A with system intact (no contingencies) 2. NERC category B contingencies a. Single element outages, at buses with a nominal voltage of 69 kv and above, in the areas (327,35,332,349,502,503,504,330,330, 356, 357, 346,347,350,55,520,524,544) b. Multiple element outages initiated by a fault with normal clearing in areas (327,35,332,349,502,503,504) 3. NERC Category C a. Selected NERC Category C events provided by adhoc study group in the study region of areas (327) 4. For all the contingencies and post-disturbance analyses, cases were solved with transformer tap adjustment enabled, area interchange adjustment disabled, phase shifter adjustment disabled (fixed) and switched shunt adjustment enabled. 5

6 D. Study Methodology Non-linear (AC) contingency analysis was performed on the benchmark and study cases, and the incremental impact of the DPP February 205 generating facilities was evaluated by comparing the steady state performance of the transmission system in the bench mark and study cases. Analysis was performed using PSSE version and PSS MUST version.0.. E. Performance Criteria A branch is considered a thermal constraint if the following conditions are met:. branch is loaded above its applicable normal or emergency rating for the post-change case 2. generator (ER/NR) has a larger than 20% DF on the overloaded facility under post contingent condition or 5% DF under system intact condition, 3. the megawatt impact due to the generator is greater than or equal to 20% of the applicable rating (normal or emergency) of the overloaded facility, or 4. the overloaded facility or the overload-causing contingency is at generator s outlet. A bus is considered a voltage constraint if both of the following conditions are met:. the bus voltage is outside of applicable normal or emergency limits for the post change case, and 2. the change in bus voltage is greater than 0.0 per unit. All generators must mitigate thermal injection constraints and voltage constraints in order to obtain any type of Interconnection Service. Further, all generators requesting Network Resource Interconnection Service (NRIS) must mitigate constraints found by using the deliverability algorithm, to meet the system performance criteria for NERC category A, and B events, if DFAX due to the generator is equal to or greater than 5%. 4. Thermal Analysis Results In the South study area, the shoulder load was 88 % summer peak load, hence only summer peak cases were studied. No constraints were seen in thermal analysis for 208 and 2025 Summer Peak scenarios due to project J39. No constraints were identified when the transmission system comprising of control areas listed in Table 2 were evaluated for Category C contingencies for area 327 causing facilities impacted by the project by a DFAX values larger than 20% DF on the overloaded facility under post contingent condition or 5% DF under system intact condition and with loadings of up to 25% or more of their emergency rating. 5. Voltage Analysis Results The voltage analysis results on 208 and 2025 Summer Peak analysis indicate that the study generator J39 does not cause any voltage violations. 6. Stability Analysis Stability analysis for J39 performed by ABB, shows that study projects did not adversely impact the system for normally cleared faults and stuck breaker faults with back up clearing. However, additional 6

7 stability analysis performed to study impact of J39 on ANO established stability limits showed that J39 adversely impacts ANO transient stability limits for two scenarios involving prior outage of J39 Pleasant Hill 500 kv line followed by SLG stuck breaker fault (B506 STK) at ANO bus. The post-fault configuration is such that Project J39 is radially connected into the ANO 500 kv bus and there is only one transmission outlet out of this bus (ANO 500/6 kv transformer) that is forced to carry the full output of the ANO plant (at its established stability limit), plus the injection from Project J39. Results show that with ANO at its established stability limits following the above mentioned prior-outage conditions and faults, it may be possible for Project J39 to inject a certain amount of power into the grid. However, considering that the thermal rating of the ANO 500/6 kv auto-transformer is more limiting for these two events, MISO and Entergy concluded that J39 needs to back down to zero (0) MW after the prior outage of J39 Pleasant Hill 500 kv line in order to reduce the flow below the thermal limits of the ANO 500/6 kv auto-transformer. Thus maximum allowable injections as derived in additional stability analysis are moot because J39 will be required to back down to 0 MW following the prior-outage of the J39 Tap Pleasant Hill 500 kv line based on thermal considerations i.e., emergency rating of the ANO 500/6 kv auto-transformer. Details pertaining to the Stability Study Reports can be found in Appendix A Stability Analysis Reports. 7. Short Circuit Analysis J39 customer has confirmed that the HVDC injection (LCC) will not contribute any short circuit currents to the AC system. Therefore, a short circuit analysis was not necessary. 8. Deliverability Study J39 being an HVDC injection, NRIS is not applicable. 9. Shared Network Upgrades Analysis performed shows there are no projects for Shared Network Upgrade cost allocation. 0. Impact on ANO thermal limits J39 would be backed down to 0 for prior outage of J39 Tap Pleasant Hill to respect the thermal rating of ANO Xmer; so as to prepare for the 2 nd contingency (B506 STK 2 ); during which ANO Xmer would be the only outlet for ANO units as well as J39. Currently ANO units are being backed down to respect ANO Xmer for this scenario; which indicates there is no additional injection available for J39. An operating guide would be considered for backing down and an SPS would not be considered for the same. 2 B506 STK contingency takes out two 500 kv lines ANO- Ft. Smith and ANO Mabelvale. 7

8 . Affected System Analysis SPP performed the affected system study to analyze the impact on SPP facilities. No SPP impacts were identified for J39 project. Details pertaining to SPP affected system analysis can be found in Appendix B SPP Affected System Study. 2. HIS /SSTI (Harmonic Impedance Scanning /Sub-synchronous Torsional Interaction) study HIS study this report is a harmonic impedance study (HIS) seen from the point of interconnection on the ANO-Pleasant Hill 500 kv line under a variety of system conditions and is limited to the Arkansas terminal. The results / plots provides the J39 Interconnection Customer / HVDC design team for use in their filter design calculations. Details pertaining to SPP affected system analysis can be found in Appendix C E7422_0060_0_r00 MISO J39 HIS Report. SSTI report describes the SSTI screening study conducted for the Midcontinent Independent System Operator (MISO) Project J39 HVDC Interconnection. The calculations in this report address the requirements outlined in Section 2.4 of ABB s Technical Proposal. The report begins with a general description of the sub-synchronous torsional interaction (SSTI) phenomenon, followed by a discussion of the SSTI screening and evaluation techniques used in the study. The results of the screening analysis for machines in the vicinity of the J39 HVDC Interconnection tap on Entergy s Arkansas Nuclear One (ANO) Pleasant Hill 500 kv line are presented in Sections 7 and 8 of this report. Based on the results of the SSTI screening analysis, and considering a reasonable number of contingences, i.e., N-5 or lower, the following generating units are identified for SSTI analysis during the detailed design phase for the J39 HVDC converters: Entergy s Arkansas Nuclear One (ANO) Units and 2 The two ANO generating units will require detailed study at the contract stage of the project using the methods discussed in this report. The Dardanelle and L&D #9 hydro generating units are the next closest generating units to exhibit unit interaction factors in excess of 0.0. However, the number of contingencies required to reach a significant level of interaction, i.e., 7, as well as the construction of the hydro units, makes sub-synchronous issues unlikely for these generating units and no further study is recommended. Details pertaining to SPP affected system analysis can be found in Appendix C E7422_000_0_r00 MISO J39 SSTI Screening Study Report 8

9 Appendix Appendix A Stability Analysis Reports The following reports provides details pertaining to stability analysis MISO_J39_Stability_Study_report_ MISO_J39_Additional_Analysis_Report_ Appendix B SPP Affected System Study SPP Affected System Study report (MISO FEB 205 Affected System Study_8-3-5) has been posted to the MISO external website. Appendix C HIS /SSTI (Harmonic Impedance Scanning /Sub-synchronous Torsional Interaction) study E7422_0060_0_r00 MISO J39 HIS Report. E7422_000_0_r00 MISO J39 SSTI Screening Study Report 9

10 INTERCONNECTION STABILITY ANALYSIS REPORT FOR PROJECT J39 AND J47 MIDCONTINENT INDEPENDENT SYSTEM OPERATOR DEFINITIVE PLANNING PHASE FEBRUARY 205 FINAL REPORT ABB REPORT #: 205-E5466 Draft Report Issued On: July 3, 205 Final Report Updated On: June 27, 206 Prepared for: Midcontinent Independent System Operator, Inc. Prepared by: ABB Inc. Power Consulting 90 Main Campus Drive Raleigh, NC i

11 Legal Notice This document, prepared by ABB Inc. (ABB), is an account of work sponsored by Midcontinent Independent System Operator, Inc. (MISO). Neither MISO nor ABB nor any person or persons acting on behalf of either party: (i) makes any warranty or representation, expressed or implied, with respect to the use of any information contained in this report, or that the use of any information, apparatus, method, or process disclosed in this report may not infringe privately owned rights, or (ii) assumes any liabilities with respect to the use of or for damages resulting from the use of any information, apparatus, method, or process disclosed in this document. ii

12 ABB Inc. Midcontinent Independent System Operator (MISO) Technical Report ABB Report #: 205-E-5466 Interconnection Stability Analysis Report for Projects J39 and J47 Update: June 27, 206 # Pages: 3 + Appendices Author(s): Reviewed by: Approved by: Xiaohuan Tan Sri Pillutla, Dave Dickmander Willie Wong EXECUTIVE SUMMARY Midcontinent Independent System Operator, Inc. (MISO) has retained ABB Power Systems Consulting to perform transient stability analysis for two interconnection requests (J39 and J47), in the Definitive Planning Phase (DPP) February 205 study cycle. Project J39 is a 500 MW HVDC project seeking interconnection in Pope County, AR. Based on the available information, this is a multi-terminal HVDC project with the rectifier station located in Oklahoma and the inverter stations located in Pope County, AR and in Shelby County, TN. The point of interconnection in Pope County, AR is on Entergy s Arkansas Nuclear One (ANO) Pleasant Hill 500 kv line. Injection into the Entergy system is 500 MW. Project J47 is a 43 MW waste heat recovery project located in Calcasieu County, LA. The point of interconnection is Entergy s Graywood 230 kv substation. The primary objective of this study is to evaluate the collective impact of these interconnection requests on stability performance in the MISO South transmission systems. A summary of the study results is presented below. Stability Analysis Stability analysis was performed on 208 and 2025 summer shoulder peak cases provided by MISO. Thirty (30) three-phase normally cleared and thirteen (3) single-line-to-ground faults with backup clearing were simulated on the post-project cases to determine the impact of J39 and J47 on angular stability and transient voltage recovery of the Entergy system. No angular instability or voltage dip violations attributed to the proposed projects were identified. Based on these results, it can be concluded that J39 and J47 do not adversely impact the stability performance of the Entergy system. A sensitivity analysis was also performed by using an updated HVDC model, which assumes a monopolar tap configuration and the HVDC rectifier end connecting to the AC system in SPP. No angular instability or voltage dip violations attributed to J39 were identified. Note (June 27, 206): J47 which was in this study had withdrawn and it was determined that additional analysis was not necessary to evaluate its impact on the ongoing analysis, as its POI being in LA was remote with respect to J39. iii

13 TABLE OF CONTENTS EXECUTIVE SUMMARY... 3 INTRODUCTION.... Description of Project... 2 STUDY METHODOLOGY AND CRITERIA Study Methodology Study Criteria STUDY MODEL DEVELOPMENT Powerflow Cases Stability Database STUDY RESULTS Summary of Results PNE HVDC Behavior HVDC Response Following a 3-Phase Fault at the 500 kv AC Tap HVDC Response Following Temporary Block of Pole HVDC Response to Permanent Block of Bipole SENSITIVITY ANALYSIS FOR PROJECT J Sensitivity Case Development Sensitivity Analysis Results HVDC Behavior in Sensitivity Analysis HVDC Response Following a 3-Phase Fault at the 500 kv AC Tap HVDC Response Following Temporary Block of Pole HVDC Response to Permanent Block of Pole HVDC Response to Permanent Block of Bipole CONCLUSIONS... 3 Appendix A LOCAL ONE-LINE DIAGRAMS Appendix B DYNAMIC MODELS B. J39 Dynamic Model B.2 J47 Dynamic Model Appendix C PROPOSED 500 KV INTERCONNECTION OF J Appendix D PLOTS OF 208 POST-PROJECT CASE Appendix E PLOTS OF 208 PRE-PROJECT CASE Appendix F PLOTS OF 2025 POST-PROJECT CASE Appendix G PLOTS OF 2025 PRE-PROJECT CASE... 4 Appendix H ONE-LINE DIAGRAM OF UPDATED J39 MODEL Appendix I PLOTS OF 208 J39 SENSITIVITY ANALYSIS Appendix J PLOTS OF 2025 J39 SENSITIVITY ANALYSIS iv

14 LIST OF TABLES Table 4-: Transient Stability with 3-Phase Normally-Cleared Faults... 9 Table 4-2: Transient Stability with SLG Stuck-Breaker Faults Cleared at Backup Clearing Time... 0 LIST OF FIGURES Figure -: Geographic Location of Proposed Project J Figure -2: One Line Diagram of Proposed Project J Figure -3: Geographic Location of Proposed Project J Figure 4-: HVDC Response to Fault J39-3PH-0: PDC, PAC, QDC, and IDC... 3 Figure 4-2: HVDC Response to Fault J39-3PH-0: VDC, VAC, Alpha, and Gamma... 4 Figure 4-3: HVDC Response to Temporary Block of Pole 2: PDC, PAC, QDC, and IDC... 5 Figure 4-4: HVDC Response to Temporary Block of Pole 2: VDC, VAC, Alpha, and Gamma... 6 Figure 4-5: HVDC Response to Permanent Block of Bipole: PDC, PAC, QDC, and IDC... 7 Figure 4-6: HVDC Response to Permanent Block of Bipole: VDC, VAC, Alpha, and Gamma... 8 Figure 5-: HVDC Pole Response to Fault J39-3PH Figure 5-2: HVDC Pole 2 Response to Fault J39-3PH Figure 5-3: HVDC Pole Response to Temporary Block of Pole Figure 5-4: HVDC Pole 2 Response to Temporary Block of Pole Figure 5-5: HVDC Pole Response to Permanent Block of Pole Figure 5-6: HVDC Pole 2 Response to Permanent Block of Pole Figure 5-7: HVDC Pole Response to Permanent Block of Bipole Figure 5-8: HVDC Pole 2 Response to Permanent Block of Bipole v

15 INTRODUCTION. DESCRIPTION OF PROJECT Midcontinent Independent System Operator, Inc. (MISO) has retained ABB Power Systems Consulting to perform transient stability analysis for two interconnection requests (J39 and J47), in the Definitive Planning Phase (DPP) February 205 study cycle. Project J39 is a 500 MW HVDC project seeking interconnection in Pope County, AR. Based on the available information, this is a multi-terminal HVDC (Plains and Eastern, PNE HVDC) project with the rectifier station located in Oklahoma and the inverter stations located in Pope County, AR and in Shelby County, TN. The point of interconnection in Pope County, AR is on Entergy s Arkansas Nuclear One (ANO) Pleasant Hill 500 kv line. Injection into the Entergy system is 500 MW. The projected in-service date for the J39 project is November, 208. Figure - shows a diagram of the transmission system in the vicinity of the proposed project. Figure -2 shows a schematic of the proposed multi-terminal HVDC system. It is understood that a new four-breaker ring bus will be developed on the ANO Pleasant Hill 500 kv line to accommodate the proposed project (See Appendix C). Project J47 is a 43 MW waste heat recovery project located in Calcasieu County, LA. The point of interconnection is Entergy s Graywood 230 kv substation. The projected in-service date for the J47 project is June 9, 207. Figure -3 shows a diagram of the transmission system in the vicinity of the proposed project.

16 Figure -: Geographic Location of Proposed Project J39 Figure -2: One Line Diagram of Proposed Project J39 User Guide for PSSE HVDC Model, Report R , Prepared by TransGrid Solutions Inc. Report date January 5,

17 Figure -3: Geographic Location of Proposed Project J47 3

18 2 STUDY METHODOLOGY AND CRITERIA 2. STUDY METHODOLOGY The purpose of the study is to identify potential angular instabilities and voltage dip violations for J39 and J47 under disturbance conditions, and the effect of the two projects on other existing generating facilities. The fault scenarios simulated in this study are listed in Table 4- and Table 4-2 The scenarios cover three-phase faults with normal clearing, single line to ground (SLG) faults with delayed clearing, and temporary or permanent blocking of the HVDC line. Fault scenarios were simulated using post- and pre-project cases such that the stability performance with and without the proposed interconnection projects could be compared. Any new stability problems attributed to the proposed interconnection projects are flagged and reported. The study area of this study is defined as zone 385 (EES_TEXAS), zone 386 (EES_GSU_LA), and zone 39 (EES_ARK). For each fault, voltages at buses rated 00 kv and above in the study area were monitored, along with selected buses in zone 30 (LAGN). In addition, rotor angles, speed deviations and electrical power outputs of the generators in the study area were also monitored. The dynamic simulations of fault scenarios were performed using the PSS/E dynamics program (version ). In each fault scenario, the fault was initiated at t =.0 seconds and the total simulation run time was 20.0 seconds. 2.2 STUDY CRITERIA Study criteria are based upon Section.A of Entergy Transmission Local Planning Criteria. The exact transient stability criteria specified in the document are shown below for reference: o o First Swing Instability Angular Criteria: If the generator rotor angle deviation with respect to a distant generator is more than 80 degrees, the generator has a potential to slip poles or become unstable. This condition is unacceptable as it will create a great stress on the generator shaft and may reduce its life span. For screening purposes, any deviation of rotor angle beyond 80 degrees is considered instability of the generator. Further analysis has to be performed in order to determine whether the generator is marginally stable or unstable by monitoring rotor angles. Voltage Dip Criteria for ZIP Load Model: 3-phase fault or single-line-ground fault (SLG) with normal clearing resulting in the loss of a single component (generator, transmission circuit or transformer) or a loss of a single component without fault: Not to exceed 20% for more than 20 cycles at any bus Not to exceed 25% at any load bus Not to exceed 30% at any non-load bus Entergy Transmission Local Planning Guidelines and Criteria, January 27,

19 3-phase faults with normal clearing resulting in the loss of two or more components (generator, transmission circuit, or transformer) or SLG fault with delayed clearing resulting in the loss of one or more components: Not to exceed 20% for more than 40 cycles at any bus Not to exceed 30% at any bus The duration of the transient voltage dip excludes the duration of the fault. The transient voltage dip criteria may not be applied to three-phase faults followed by stuck breaker conditions unless the determined impact is extremely widespread. In this study, a load bus is defined as any bus with one or more directly connected loads in the PSS/E case. Conversely, any bus without a directly connected load is defined as a non-load bus. 5

20 3 STUDY MODEL DEVELOPMENT 3. POWERFLOW CASES The following two powerflow cases were provided by MISO and served as the starting point of this analysis: 208SH_DYN_FEB5R_South_DPP_065205_REV2_STUDY.sav 2025SH_DYN_FEB5R_South_DPP_065205_REV2_STUDY.sav Both J39 and J47 were modeled and fully dispatched in the above cases. A review of the above-mentioned cases revealed the following modeling approximations for Project J39 these were brought to the attention of MISO: Project J39 is not connected to the Optima 345 kv bus at the rectifier end of the HVDC line as shown in Figure -2. Instead, it is connected radially to a 345 kv ac rectifier bus to which a 4300 MW equivalent generator is connected (the 345 kv ac bus is not connected to the rest of the Oklahoma transmission network). It is not known whether the impedance of the equivalent generator is representative of the short-circuit strength of the Oklahoma transmission network. The equivalent generator at the rectifier end of Project J39 is modeled as a classical generator (GENCLS model in PSS/E) and not using wind turbine-generator (WTG) models. The representation of the J39 HVDC system configuration as received from MISO is assumed to be preliminary and the PSS/E model of this project should be reviewed when a final design configuration is available. It should be noted that proper representation of the transmission system and the wind generation at the rectifier end are critical to the overall performance of the proposed HVDC link. A sensitivity analysis will be required to verify whether the findings of this study may be impacted after the above-mentioned modeling approximations have been addressed. Section 5 in this report provides the details of the sensitivity analysis. The above-mentioned cases were modified slightly to address initialization errors this included netting out a limited number of small generating units remote from the Entergy system that exhibited initialization errors. Also, it was seen that some remote generating units were dispatched below their minimum power ratings (Pmin) this resulted in initialization errors. Such units were dispatched off-line. Other minor fixes were made to the cases such that the no-disturbance run simulation results are acceptable by ABB s engineering judgement. The updated cases were called post-project cases hereafter in this report. The pre-project cases were developed based on the post-project cases by making the following changes: Model projects J39 and J47 out-of-service. Dispatch against generation in TVA. 6

21 One-line diagrams for the local area with the proposed projects are presented in Appendix A. 3.2 STABILITY DATABASE The stability database used for this study was provided by MISO. Specifically, the files provided are: o MTEP4_DYN_FEB5.snp dated 5/26/205 o Dynamic link library file DSUSR.DLL file dated 5/22/205 o Dynamic link library associated with user-written model for the PNE HVDC line file PNE.DLL dated 2//204 During the initial review of the dynamic models, some dynamic data errors were observed in the snapshot, which were identified and corrected. Modeling details of projects J39 and J47 are presented in Appendix B. 7

22 4 STUDY RESULTS 4. SUMMARY OF RESULTS Thirty (30) three-phase faults with normal clearing and thirteen (3) single-line-to-ground faults with backup clearing were simulated for the post-project cases, which are tabulated in Table 4- and Table 4-2, respectively. Applicable faults were also simulated for the pre-project cases. The breaker diagram for the proposed 500 kv interconnection of J39 was provided by MISO and is shown in Appendix C. In summary, the simulation results indicate that: No stability violations attributed to J39 and J47 were identified using Entergy s First Swing Angular Instability Criteria and Voltage Dip Criteria. The only fault that exhibits angular instability is Fault #J39-SLG-09, which is a SLG fault at the White Bluff 500 kv substation followed by tripping of the White Bluff Sheridan 500 kv line at the primary clearing time and the White Bluff Keo 500 kv line at the backup clearing. Both 500 kv lines are the White Bluff generation station outlets. The White Bluff generation (approximately 650 MW) should probably have been tripped following this contingency because the 500/5 and 500/230 kv transformers at White Bluff cannot support this much generation. The fault idev file provided by MISO does not include any special protection scheme to trip the White Bluff units for this contingency though. Since the system was unstable following this fault in both pre-project and post-project cases, the angular instability is not attributed to J39 and J47. Plots for all simulations of 208 and 2025 cases are provided in Appendix D through Appendix G. For each fault simulation performed on the post-project cases, the following eight (8) pages of plots are provided: Page : Rotor angle of the selected units monitored in the study area Page 2: Speed deviation of the monitored units Page 3: Active power generation (PELEC) of the monitored units Page 4: Reactive power generation (QELEC) of the monitored units Page 5: J39 and J47 local bus voltages Page 6: J39 and J47 local bus voltages Page 7: PNE HVDC model variables o Quadrant PDC, DC power (MW) at the rectifier, inverter, and tap end o Quadrant 2 PAC, AC power (MW) at the rectifier, inverter, and tap end o Quadrant 3 QAC, Reactive power (MVAr) at the rectifier, inverter, and tap end o Quadrant 4 IDC, DC current (ka) at the rectifier, inverter, and tap end Page 8: PNE HVDC model variables o Quadrant VDC, DC voltage (pu) at the rectifier, inverter, and tap end o Quadrant 2 VAC, AC voltage (MW) at the rectifier, inverter, and tap end o Quadrant 3 Alpha, firing angle (rad) at the rectifier, inverter, and tap end o Quadrant 4 Gamma, extinguish angle (rad) at the rectifier, inverter, and tap end 8

23 Page through Page 6 are plotted for all simulations performed on the pre-project cases. Note that all simulations were simulated for 20 seconds but plotted the first 0 seconds to facilitate better resolution during the transient stage. Table 4-: Transient Stability with 3-Phase Normally-Cleared Faults Fault # Fault Location Tripped Element J39 Faults Clearing Time (cycles) 208 Pre Stability Performance 208 post 2025 pre 2025 post J39-3PH-0 J39 Tap 500 kv J39 Tap Pleasant Hill 500 kv line 5.0 NA stable NA stable J39-3PH-02 J39 Tap 500 kv J39 Tap ANO 500 kv line 5.0 NA stable NA stable J39-3PH-03 ANO 500 kv ANO - J39 Tap 500 kv line 5.0 NA stable NA stable J39-3PH-04 ANO 500 kv ANO Ft Smith 500 kv line 5.0 stable stable stable stable J39-3PH-05 ANO 500 kv ANO Mabelvale 500 kv line 5.0 stable stable stable stable J39-3PH-06 Mabelvale 500 kv Mabelvale ANO 500 kv line 5.0 stable stable stable stable J39-3PH-07 Pleasant Hill 500 kv Pleasant Hill Mayflower 500 kv line 5.0 stable stable stable stable J39-3PH-08 Mayflower 500 kv Mayflower Mabelvale 500 kv line 5.0 stable stable stable stable J39-3PH-09 Mabelvale 500 kv Mabelvale Sheridan 500 kv line 5.0 stable stable stable stable J39-3PH-0 Mabelvale 500 kv Mabelvale Wrightsville 500 kv line 5.0 stable stable stable stable J39-3PH- Wrightsville 500 kv Mabelvale Wrightsville 500 kv line 5.0 stable stable stable stable J39-3PH-2 Keo 500 kv Keo West Memphis 500 kv line 5.0 stable stable stable stable J39-3PH-3 ANO 500 kv ANO 500/6/22 kv Xfmr 5.5 stable stable stable stable J39-3PH-4 ANO 500 kv ANO Pleasant Hill 500 kv 5.0 stable NA stable NA J39-3PH-5 Shelby 500 kv Shelby PE INV BUS 500 kv line # 5.0 NA stable NA stable J39-3PH-6 Temporary Block of Pole 2 PNE Pole 2 Blocked for 250 ms 5.0 NA stable NA stable J39-3PH-7 Permanent Block of Pole 2 PNE Pole 2 Blocked permanently NA NA stable NA stable J39-3PH-8 Permanent Block of Bipole PNE Bipole Blocked permanently NA NA stable NA stable J47 Faults J47-3PH-0 J47 Tap 230 kv J47 Pecan Grove 230 kv line 5.0 NA stable NA stable J47-3PH-02 J47 Tap 230 kv J47 Graywood 230 kv line 5.0 NA stable NA stable J47-3PH-03 Calcasieu 230 kv Calcasieu Pecan Grove 230 kv line 5.0 stable stable stable stable J47-3PH-04 Calcasieu 230 kv Calcasieu Boudoin 230 kv line 5.0 stable stable stable stable J47-3PH-05 Boudoin 230 kv Boudoin Calcasieu 230 kv line 5.0 stable stable stable stable J47-3PH-06 Boudoin 230 kv Boudoin Carlyss 230 kv line 5.0 stable stable stable stable J47-3PH-07 Sabine 230 kv Sabine China 230 kv line 5.0 stable stable stable stable J47-3PH-08 Graywood Tap 230 kv Graywood Tap Solac 230 kv line 5.0 stable stable stable stable J47-3PH-09 Solac 230 kv Solac Chalkley 230 kv line 5.0 stable stable stable stable J47-3PH-0 Nelson 230 kv Nelson Carlyss 230 kv line 5.0 stable stable stable stable J47-3PH- Hartburg 500 kv Hartburg Cypress 500 kv line 5.0 stable stable stable stable J47-3PH-2 Nelson 500 kv Nelson Richard 500 kv line 5.0 stable stable stable stable J47-3PH-3 Nelson 500 kv Nelson Hartburg 500 kv line 5.0 stable stable stable stable 9

24 Table 4-2: Transient Stability with SLG Stuck-Breaker Faults Cleared at Backup Clearing Time Fault # Fault location Primary Tripping Backup Clearing Tripping Primary Clearing (cycles) Back-up Clearing (cycles) 208 pre Stability Performance 208 post 2025 pre 2025 post J39 Faults J39-SLG-0 ANO 500 KV ANO U2 and GSU No Tripping 5.00 none stable stable stable stable J39-SLG-02 ANO 500 kv ANO Ft Smith 500kV line ANO Mabelvale 500 kv stable stable stable stable J39-SLG-03 ANO 500 KV ANO Mabelvale 500 kv line ANO Ft Smith 500 kv line stable stable stable stable J39-SLG-04 ANO 500 kv ANO 500/6/22 kv Xfmr ANO J39 Tap 500 kv NA stable NA stable J39-SLG-4a ANO 500 kv ANO 500/6/22 kv Xfmr ANO Pleasant Hill 500 kv stable NA stable NA J39-SLG-05 J39 TAP 500 kv J39 Tap Pleasant Hill 500 kv line Pleasant Hill Mayflower 500 kv line NA stable NA stable J39-SLG-06 J39 TAP 500 kv J39 Tap ANO 500 kv line J39TAP 500 kv Pole # NA stable NA stable J39-SLG-07 J39 TAP 500 kv J39 Tap Pleasant Hill 500 kv line J39TAP 500 kv Pole # NA stable NA stable J39-SLG-08 Pleasant Hill 500 kv Pleasant Hill Mayflower 500 kv line Pleasant Hill J39 Tap 500 kv line NA stable NA stable J39-SLG-09 White Bluff 500 kv White Bluff Sheridan 500 kv line White Bluff Keo 500 kv line unstable unstable unstable unstable J47 Faults J47-SLG-0 Nelson 230 kv Nelson 230 kv north bus, Nelson U4 and U6 NA various stable stable stable stable J47-SLG-02 Sabine 230 kv Sabine 230/38 kv auto 38 kv side No tripping stable stable stable stable J47-SLG-03 Nelson 230 kv Nelson Moss Bluff 230 kv line Nelson Penton Rd 230 kv line stable stable stable stable J47-SLG-04 Sabine 230 kv Sabine China 230 kv line No tripping stable stable stable stable Note: All fault clearing times refer to the elapsed time from the inception of a given fault. That is 4.5- cy+7.75 cy = 2.25 cy. Similarly, 5.5 cy +8.5 cy = 4 cy etc. 0

25 4.2 PNE HVDC BEHAVIOR The post-fault response of the PNE HVDC line was reviewed for a limited number of contingencies including faults in the AC network, and temporary or permanent blocks of the HVDC line. In all contingencies, the initial disturbance is applied at t = sec HVDC Response Following a 3-Phase Fault at the 500 kv AC Tap The dynamic response of the PNE HVDC was reviewed in more detail by considering Fault # J39-3PH-0 in 208, which is a three-phase normally-cleared 5 cycle fault at the J39 Tap end of the J39 Tap - Pleasant Hill 500 kv line. Figure 4- and Figure 4-2 show the following HVDC variables from 0.9 seconds to.9 seconds: Figure 4-: o Quadrant PDC, DC power (MW) at the rectifier, inverter, and tap end o Quadrant 2 PAC, AC power (MW) at the rectifier, inverter, and tap end o Quadrant 3 QAC, Reactive power (MVAr) at the rectifier, inverter, and tap end o Quadrant 4 IDC, DC current (ka) at the rectifier, inverter, and tap end Figure 4-2: o Quadrant VDC, DC voltage (pu) at the rectifier, inverter, and tap end o Quadrant 2 VAC, AC voltage (pu) at the rectifier, inverter, and tap end o Quadrant 3 Alpha, firing angle (rad) at the rectifier, inverter, and tap end o Quadrant 4 Gamma, extinguish angle (deg) at the rectifier, inverter, and tap end Figure 4-2 shows the AC voltage at the J39 Tap 500 kv bus dropping to zero upon fault inception and recovering quickly following fault clearing. The fault results in commutation failure causing DC voltages to collapse at the rectifier, inverter and tap terminals of the bipole. This results in a temporary reduction of DC power to zero during commutation failure (see Figure 4-). After fault clearing, as AC voltages recover to their pre-fault levels, the DC power recovers according to the characteristics of the voltage dependent current order limiter (VDCOL) function at each station. A review of Figure 4- shows that DC power is first ramped up at the rectifier and inverter ends followed by a gradual ramp up at the tap end. This delay may be intentional to allow for optimal power recovery at the rectifier and inverter ends of the DC line and prevent the possibility of repeated commutation failures at the tap during recovery. Figure 4- shows that DC power at the tap is restored to 500 MW around.45 seconds or approx. 350 msec. after fault clearing HVDC Response Following Temporary Block of Pole 2 Figure 4-3 and Figure 4-4 illustrate system response following a temporary block of one of the two poles of the HVDC line. For simulation purposes, it is assumed that Pole 2 is blocked and then restarted after 250 msec. This emulates the effect of a temporary DC line fault, in terms of momentary interruption of the power transfers on the HVDC system. Following the temporary block, the DC power on Pole 2 drops to zero. Based on the available information, the user-written model for the PNE HVDC line does not include provisions for an overload capability on the healthy pole. Therefore, the healthy pole does not carry the power that is normally carried on the pole that is blocked. Figure 4-3 shows the DC power on Pole 2 dropping to zero when it is blocked. The DC power on the healthy pole (Pole ) experiences a slight reduction from 250 MW down to about 225 MW

26 this is due to a slight drop in the DC voltage on Pole. The DC current on the healthy pole remains unaffected by the pole block. Figure 4-4 shows a slight increase in AC voltages at all three terminals of the DC line when Pole 2 is blocked. This is because the filters at the terminals of the DC line continue to remain in service during the temporary block. After Pole 2 is unblocked at.25 seconds, the DC current on that pole rapidly increases toward its pre-fault level. This results in an increased reactive power absorption particularly at the rectifier and inverter ends of the DC line causing voltages at these terminals to sag. The lost MW-seconds during the HVDC power interruption has also resulted in machine rotor angles in the AC network to be different from their pre-disturbance values, which also can contribute to AC voltage effects during the HVDC recovery. See Figure 4-3. There is minimal impact on the AC voltages at the tap end. See Figure 4-4. It should be noted that this simulation is not realistic in that it does not emulate a DC line fault. For a DC line fault, there will be a DC overcurrent that the rectifier will see. Similar to the DC overcurrent for an AC fault at the tap, this DC overcurrent at the rectifier results in a momentary increase of reactive power absorbed from the rectifier AC network. The rectifier control system responses to the DC overcurrent by increasing Alpha, and the DC line fault protection will force Alpha to high values (rectifier retard) to discharge the line. After a few hundred milliseconds, the rectifier retard is released and the converters restart. This results in a behavior very different from this simulation. Our understanding is that this PNE HVDC line model cannot simulate a DC line fault and associated rectifier retard HVDC Response to Permanent Block of Bipole Figure 4-5 and Figure 4-6 illustrate HVDC response after permanently blocking the HVDC bipole. For simulation purposes, it is assumed that all 4300 MW of wind generation is cross-tripped at the instant of the bipole block. AC filter banks at the rectifier end are also cross-tripped at the instant of the bipole block (strictly speaking, the wind generation and filter banks are tripped a few milliseconds after the bipole block; however, this delay was not simulated). Figure 4-5 and Figure 4-6 show DC currents and voltages dropping to zero at t =.0 second. AC voltages at the inverter and tap terminals experience over-voltages because the filters at these terminals are assumed to be in-service. AC voltages at the J39 tap bus increase to.7 pu these over-voltages can be mitigated by tripping the AC filter banks (in general, these filter banks are automatically tripped with a short time delay after the bipole block). 2

27 MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-0-J39TAP-PleasantHill-500kV.out CHNL# 65: [PNE-2 PAC_TAP2 (MW)] CHNL# 609: [PNE- PAC_TAP (MW)] CHNL# 67: [PNE-2 PAC_INV2 (MW)] CHNL# 6: [PNE- PAC_INV (MW)] CHNL# 63: [PNE-2 PAC_REC2 (MW)] CHNL# 607: [PNE- PAC_REC (MW)] WED, JUL :58 PAC, AC POWER (MW) MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-0-J39TAP-PleasantHill-500kV.out CHNL# 570: [PNE-2 IDC_INV (KA)] CHNL# 569: [PNE-2 IDC_TAP (KA)] CHNL# 568: [PNE-2 IDC_REC (KA)] CHNL# 567: [PNE- IDC_INV (KA)] CHNL# 566: [PNE- IDC_TAP (KA)] CHNL# 565: [PNE- IDC_REC (KA)] MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-0-J39TAP-PleasantHill-500kV.out CHNL# 563: -[PNE-2 PDC_TAP (MW)] CHNL# 560: -[PNE- PDC_TAP (MW)] CHNL# 564: -[PNE-2 PDC_INV (MW)] CHNL# 56: -[PNE- PDC_INV (MW)] CHNL# 562: [PNE-2 PDC_REC (MW)] CHNL# 559: [PNE- PDC_REC (MW)] WED, JUL : PDC, DC POWER (MW).7000 MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-0-J39TAP-PleasantHill-500kV.out CHNL# 576: [PNE-2 QAC_INV (MVAR)] CHNL# 575: [PNE-2 QAC_TAP (MVAR)] CHNL# 574: [PNE-2 QAC_REC (MVAR)] CHNL# 573: [PNE- QAC_INV (MVAR)] CHNL# 572: [PNE- QAC_TAP (MVAR)] CHNL# 57: [PNE- QAC_REC (MVAR)] WED, JUL : WED, JUL : IDC, DC CURRENT (KA) QAC, REACTIVE POWER (MVAR

28 MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-0-J39TAP-PleasantHill-500kV.out CHNL# 582: [PNE-2 VAC_INV (PU)] CHNL# 58: [PNE-2 VAC_TAP (PU)] CHNL# 580: [PNE-2 VAC_REC (PU)] CHNL# 579: [PNE- VAC_INV (PU)] CHNL# 578: [PNE- VAC_TAP (PU)] CHNL# 577: [PNE- VAC_REC (PU)] WED, JUL :58 VAC, AC VOLTAGE (PU) MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-0-J39TAP-PleasantHill-500kV.out CHNL# 594: [PNE-2 GAMMA_INV (DEG)] CHNL# 593: [PNE-2 GAMMA_TAP (DEG)] CHNL# 592: [PNE-2 GAMMA_REC (DEG)] CHNL# 59: [PNE- GAMMA_INV (DEG)] CHNL# 590: [PNE- GAMMA_TAP (DEG)] CHNL# 589: [PNE- GAMMA_REC (DEG)] MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-0-J39TAP-PleasantHill-500kV.out CHNL# 606: [PNE-2 VDC_INV (PU)] CHNL# 605: [PNE-2 VDC_TAP (PU)] CHNL# 604: [PNE-2 VDC_REC (PU)] CHNL# 603: [PNE- VDC_INV (PU)] CHNL# 602: [PNE- VDC_TAP (PU)] CHNL# 60: [PNE- VDC_REC (PU)] WED, JUL : VDC, DC VOLTAGE (PU).7000 MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-0-J39TAP-PleasantHill-500kV.out CHNL# 588: [PNE-2 ALFA_INV (RAD)] CHNL# 587: [PNE-2 ALFA_TAP (RAD)] CHNL# 586: [PNE-2 ALFA_REC(RAD)] CHNL# 585: [PNE- ALFA_INV (RAD)] CHNL# 584: [PNE- ALFA_TAP (RAD)] CHNL# 583: [PNE- ALFA_REC(RAD)] WED, JUL : WED, JUL : GAMMA (RAD) ALPHA (RAD)

29 MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-6-Block-PNE-Pole2-250ms.out CHNL# 65: [PNE-2 PAC_TAP2 (MW)] CHNL# 609: [PNE- PAC_TAP (MW)] CHNL# 67: [PNE-2 PAC_INV2 (MW)] CHNL# 6: [PNE- PAC_INV (MW)] CHNL# 63: [PNE-2 PAC_REC2 (MW)] CHNL# 607: [PNE- PAC_REC (MW)] WED, JUL :57 PAC, AC POWER (MW) MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-6-Block-PNE-Pole2-250ms.out CHNL# 570: [PNE-2 IDC_INV (KA)] CHNL# 569: [PNE-2 IDC_TAP (KA)] CHNL# 568: [PNE-2 IDC_REC (KA)] CHNL# 567: [PNE- IDC_INV (KA)] CHNL# 566: [PNE- IDC_TAP (KA)] CHNL# 565: [PNE- IDC_REC (KA)] MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-6-Block-PNE-Pole2-250ms.out CHNL# 563: -[PNE-2 PDC_TAP (MW)] CHNL# 560: -[PNE- PDC_TAP (MW)] CHNL# 564: -[PNE-2 PDC_INV (MW)] CHNL# 56: -[PNE- PDC_INV (MW)] CHNL# 562: [PNE-2 PDC_REC (MW)] CHNL# 559: [PNE- PDC_REC (MW)] WED, JUL : PDC, DC POWER (MW).7000 MTEP4_209SH_FINAL 204 AUG DPP STUDY; STABILITY BASE CASE FILE: 208-post_J39-3PH-6-Block-PNE-Pole2-250ms.out CHNL# 576: [PNE-2 QAC_INV (MVAR)] CHNL# 575: [PNE-2 QAC_TAP (MVAR)] CHNL# 574: [PNE-2 QAC_REC (MVAR)] CHNL# 573: [PNE- QAC_INV (MVAR)] CHNL# 572: [PNE- QAC_TAP (MVAR)] CHNL# 57: [PNE- QAC_REC (MVAR)] WED, JUL : WED, JUL : IDC, DC CURRENT (KA) QAC, REACTIVE POWER (MVAR