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HomeMy WebLinkAboutS. Intertie Phase 1 6-14-1996 studyPROJECT NO: 120293-01 2 ISSUED TO:(.. Spe \\ COPY NO. OOd CHUGACH ELECTRIC ASSOCIATION, INC. CONTRACT NO. 95-208 SOUTHERN INTERTIE ROUTE SELECTION STUDY PHASE 1 June 14, 1996 FINAL STUDIES SECTION REPORT VOLUME | OF Iil FOR INFORMATION CONTACT: = Ron Beazer, P.E. =» Randy Pollock, P.E. =» Tim Ostermeier, P.E. POWER ENGINEERS, INC. @ P.O. BOX 1066 @ HAILEY, IDAHO 83333 (208) 788-3456 @ FAX (208) 788-2082 SOUTHERN INTERTIE ROUTE SELECTION STUDY PHASE 1 SYSTEM STUDY REPORT SECTION VOLUME I OF Ill TABLE OF CONTENTS 1, ELECTRICAL SYSTEM STUDY SUMMARY 1.1 INTRODUCTION 1.2 ELECTRICAL SYSTEM ALTERNATIVES 1.3” ELECTRICAL SUMMARY AND CONCLUSIONS 1.4 SYSTEM STUDY SUMMARY 2. ELECTRICAL SYSTEM STUDIES 2.1 GENERAL 2.2 SYSTEM STUDIES, CRITERIA AND ASSUMPTIONS 2.3 LOAD FLOW STUDIES 2.4 ALTERNATIVE N-1 ANALYSIS 2.5 ALTERNATIVE DYNAMIC STABILITY ANALYSIS APPENDIX A - ASCC PLANNING CRITERIA APPENDIX B - N-1 VOLTAGE VIOLATION APPENDIX C - BELUGA ROUTE CORRESPONDENCE APPENDIX D - PUBLISHED PAPERS REGARDING TCSC AND BES SYSTEMS VOLUME II OF III - LOAD FLOW DIAGRAMS VOLUME III OF III - STABILITY ANALYSIS PAGE I-1 I-2 1-4 1-9 II-1 II-3 II-9 TI-19 TI-26 SOUTHERN INTERTIE ROUTE SELECTION STUDY PHASE 1 SYSTEM STUDY REPORT SECTION VOLUME I OF III TABLE OF TABLES Table 1A: 115kV/138kV - Alternative Load Flow and Summary Table 1B: 230kV - Alternative Load Flow and Summary Table 2: Maximum Available Power for Transfer from the Kenai to Anchorage Table 3: Scheduled Power for Transfer from the Kenai to Anchorage Table 4: Alternative 1 - Do Nothing - Load Flow and Loss Summary Table 5: Alternative 1B - Add Shunt Capacitors - Load Flow and Loss Summary Table 6: Alternative 1C - Convert to 230kV - Load Flow and Loss Summary Table 7: Alternative 2 - Parallel Existing at 138kV - Load Flow and Loss Summary Table 8: Alternative 2A - Parallel Existing at 138kV with Overhead Crossing Bird Point - Load Flow and Loss Summary Table 9: Alternative 2B - Parallel Existing at 230kV - Load Flow and Loss Summary Table 10: Alternative 2C - Parallel Existing at 230kV with Overhead Crossing at Bird Point - Load Flow and Loss Summary Table 11: Alternative 3 - Enstar Route at 138kV - Load Flow and Loss Summary Table 12: Alternative 3A - Enstar Route at 230kV - Load Flow and Loss Summary Table 13: Alternative 4 - Tesoro Route at 138kV - Load Flow and Loss Summary Table 14: Alternative 4A - Tesoro Route at 230kV - Load Flow and Loss Summary Table 15: Alternative 5 - Beluga Route at 138kV - Load Flow and Loss Summary Table 16: Alternative SA - Beluga Route at 230kV - Load Flow and Loss Summary Table 17: Summary of N-1 Analysis for the Southern Intertie Existing System 2015 with Initial 7OMW Transfer from Hope Table 18: Summary of N-1 Analysis for the Southern Intertie Parallel Route 138kV - 2015 with Initial 125MW Transfer Table 19: Summary of N-1 Analysis for the Southern Intertie Parallel Route 230kV - 2015 with Initial 125MW Transfer PAGE 1-6 I-7 II-2 II-2 II-10 I-12 I-12 II-13 II-14 II-14 II-15 TI-15 TI-16 TI-16 II-17 II-17 I-18 II-20 I-20 II-22 SOUTHERN INTERTIE ROUTE SELECTION STUDY PHASE 1 SYSTEM STUDY REPORT SECTION VOLUME I OF III TABLE OF TABLES (continued) PAGE Table 20: Summary of N-1 Analysis for the Southern Intertie Enstar Route 138kV - 2015 with Initial 125MW Transfer II-23 Table 21: Summary of N-1 Analysis for the Southern Intertie Enstar Route ~230kV = 2015 with Initial" 125MW Transfer I-23 Table 22: Summary of N-1 Analysis for the Southern Intertie Tesoro Route 138kV - 2015 with Initial 125MW Transfer II-24 Table 23: Summary of N-1 Analysis for the Southern Intertie Enstar Route 230kV - 2015 with Initial 12SMW Transfer TI-25 TABLE OF FIGURES PAGE Figure 1: Color Map 1-8 Figure 2: Area Load, Generation & Transfers - Winter 1997 II-5 Figure 3: Area Load, Generation & Transfers - Winter 2015 II-6 Figure 4: Area Load, Generation & Transfers - Summer 1997 - Maximum Transfer from Kenai Il-7 Figure 5: Area Load, Generation & Transfers - Summer 1997 - Transfer to Kenai II-8 Figure 6: Electrical Study - Existing Route Il-5 I. ELECTRICAL SYSTEM STUDY SUMMARY 1.1 INTRODUCTION This report presents the preliminary results of a screening study for proposed upgrades to the Anchorage-Kenai electric power transmission system. The study was performed by POWER Engineers, Inc. (POWER) under Chugach Contract #95-208 for Chugach Electric Association, Manager of the Southern Intertie Project for the Intertie Participants Group (IPG). The objectives of the Electrical System Studies were to determine the following: The “Pre-Contingency Secure” transfer rating of the intertie alternatives; The “Pre-Contingency Emergency” transfer rating of the intertie alternatives; The “Post-Contingency Emergency” transfer rating of the intertie alternatives; The dynamic system response for each alternative to selected disturbances; and The major equipment (transmission lines and voltage classes, step-up and step-down Transformers, reactive compensation, etc.) required for each alternative. wee Si This report presents the findings of the electrical system studies of: 1. The existing intertie; 2. The new intertie options; and 3. The installation of Battery Energy Storage either on the Kenai Peninsula or in Anchorage or both locations. Areas covered by the electrical system studies include: e load flow cases to evaluate system voltages, transmission line flows, generation schedules and equipment requirements for steady-state operation of the alternatives; ¢ single contingency outage cases (N-1) to determine the steady-state voltages and transmission line loadings for the system after a single portion of the system is removed from service (outaged); e dynamic stability cases to assess the dynamic response of the system to disturbances, such as faults or loss of generation, and to determine operating and equipment requirements to minimize the impacts to the system; and e listing of the major equipment requirements for each alternative. PEI-HLY 23-017 (6/96) Final 120293-01/rh |-1 The seven ‘Railbelt’ utilities that form the Intertie Participants Group (IPG), which provided system data and input during the study, are: Fairbanks Municipal Utility System (FMUS) Golden Valley Electric Association (GVEA) Matanuska Electric Association (MEA) Chugach Electric Association (CEA) Anchorage Municipal Light and Power (AML&P) Seward Electric Association (SEA) ~ Homer Electric Association (HEA) 1.2 ELECTRICAL SYSTEM ALTERNATIVES At the project initiation meeting, held at Chugach’s offices in Anchorage on November 30, 1995, the alternatives to be considered in the electrical system studies for this phase were finalized. These were: ALTERNATIVE 1 - DO NOTHING: Assess the capabilities of the existing intertie from Daves Creek Substation to the University Substation with the existing system and planned improvements. Sub-alternatives of the existing line were also analyzed to evaluate the possible upgrade options to the existing intertie to preclude the need for a second intertie. ALTERNATIVE 2 - PARALLEL THE EXISTING LINE: The assumed electrical model for this alternative considered a new intertie line that roughly parallels the existing intertie line route through Portage. It includes an optional alternative line that is routed north from the Hope Substation with overhead construction to a crossing of Turnagain Arm from Snipers Point to Bird Point. The Turnagain Arm (Bird Point) crossing could be either overhead or submarine cable type construction. For this analysis, it was agreed that the new intertie would not have taps to the existing distribution substations along the route. This alternative was analyzed for both 138kV and 230kV operation. ALTERNATIVE 3 - ENSTAR ROUTE: This alternative considered a new intertie from the Soldotna Substation to the International Substation. The assumed electrical model for the alternative parallels the existing line from Soldotna with an overhead transmission line that would turn north near Sterling, traverse along the east side of the wildlife refuge, change to submarine cable across Turnagain Arm, and go back to overhead construction from the submarine landing site to the International Substation. This route would generally parallel the Enstar Pipeline and considered alternatives for 138kV and 230kV operation. PEI-HLY 23-017 (6/96) Final 120293-01/rh 1-2 ALTERNATIVE 4 - TESORO ROUTE: This alternative considered a new intertie from the Bernice Lake Power Plant to Point Woronzof. It generally parallels the Tesoro pipeline. The assumed electrical model was an overhead transmission line that would run northeast from Bernice Lake along the Cook Inlet, include a four-mile section of underground cable through Captain Cook State Park, return to overhead construction to Point Possession, and change to submarine cable across to the Point Woronzof Substation. This alternative was analyzed for both for 138kV and 230kV operation. ...ALTERNATIVE.5 » BELUGA ROUTE:-— This alternative considered a new intertie from Bernice Lake Power Plant Substation across Cook Inlet to the Beluga Power Plant Substation. The assumed electrical model was an overhead transmission line that would run northeast along the east side of Cook Inlet, include a four-mile section of underground cable through Captain Cook State Park, return to overhead construction to Gray Cliff, change to submarine cable across Cook Inlet to North Foreland, and return to overhead construction from North Foreland to Beluga Power Plant. This alternative was also analyzed at both 138kV and 230kV operation. ALTERNATIVE 6 - BATTERY ENERGY STORAGE (BES): Install BES on the Kenai Peninsula or in Anchorage or both locations to allow increased flows on the existing intertie. The analysis of these installations was limited to the system’s dynamic stability, since they do not affect the steady-state performance of the existing intertie. At the project initiation meeting, the participants discussed whether the routes selected for the electrical models would reasonably fit with possible routes selected in the environmental screening study. It was agreed that the alternatives selected for the electrical models should be able to accurately predict the requirements for system operation and equipment for almost any alternative route that could reasonably be a candidate for permitting. If further refinement or analysis of the electrical system is required, this would be accomplished in Phase 2 of this project. The New Intertie transmission line alternatives are illustrated in Figure 1 on page I-8. PEI-HLY 23-017 (6/96) Final 120293-01/rh 1-3 1.3 ELECTRICAL SYSTEM SUMMARY AND CONCLUSIONS Based on our analysis, we arrived at the following conclusions: @ The existing intertie is not a good candidate for improvements to allow a long-term power transfer greater than 7OMW due to high losses. The existing intertie capacity can be increased to 125MW with the addition of shunt capacitors to support the voltage and replacement of the 4.55 miles of Brahma (203kcmil conductor which is -- thermally_limited -to 70MW)-between.Indian and-Girdwood. —It.should be-noted that the 4.55 miles of Brahma are scheduled to be changed out in the near future. Increasing the transfer from 70MW to 125MW increases losses on the intertie from 6.9MW to 25MW. Due to the high losses, this is not an attractive alternative for continuous operation. Even with the modifications, the existing line would not meet the ASCC “Pre-Contingency Secure” criteria for the system to withstand an N-1 loss of the existing intertie without tripping load or exceeding the ASCC voltage range. = Construction of a new 138kV intertie provides good performance for increasing the transfer capacity, with both interties in service, up to the maximum excess generation capacity on the Kenai of I9OMW. All four of the 138kV alternatives studied exhibit similar operational characteristics, however, the Enstar and Tesoro Routes maintain higher voltages in the Anchorage area if the existing intertie is outaged under peak load. Additionally, the line reactors associated with the Enstar and Tesoro Routes can be switched off-line to allow the cable capacitance to further improve the voltage. Losses on the Enstar and Tesoro routes are slightly less than losses on the Parallel and Beluga routes. The Bird Point crossing on the parallel route is a viable option, from an electrical perspective. If the Bird Point Crossing is constructed with undersea cable, there would be similar advantages as with the Enstar and Tesoro routes for reactor switching, although the reactors will be smaller and the voltage support less than the other two alternatives The stability studies indicate that the 138kV interties have a slight advantage over the 230kV interties, for the loss of the new intertie, because the pre-event current is more evenly split between the interties. With respect to selecting a preferred route alternative, electrical performance will not be the deciding factor. Route selection can be based on cost and permitting issues. @ Alternatives for the 230kV intertie options also perform well. The only advantages that the 230kV routes have over the 138kV construction are slightly reduced losses. The 230kV alternatives have the disadvantage of requiring more equipment in the form of reactors and power transformers than the 138kV construction. The analysis shows that 230kV intertie options will be under-utilized unless additional generation resources are developed on the Kenai. There is no significant difference in system operation between 230kV and 138kV interties. ® Battery Energy Storage in Anchorage and on the Kenai improves system stability, but due to the limits of the existing intertie, there is no real increase in the transfer PEI-HLY 23-017 (6/96) Final 120293-01/rh 1-4 capability. To increase the existing intertie capacity, the improvements listed in the following paragraph would need to be constructed. The losses would increase to 25MwW for a transfer of 125MW. To improve the losses on the existing intertie for a 125MW or higher transfer, a majority of the line would need to be reconductored for a small improvement or the line rebuilt at 230kV. @ All intertie options require reinforcement of the existing intertie to allow emergency transfer of up to 125MW and maintain system stability. The emergency transfers would need to be reduced to the existing line rating in a short period. Reinforcement - —would-consist -of-the-planned reconductoring-of the-4.55-miles of-Brahma conductor and installation of either a Static Var System (SVS) or a Thyristor Controlled Series Capacitor (TCSC) to control the voltage drop. Both the SVS and the TCSC can activate within the time frames required to enhance system stability. Use of these systems would require additional study and refinement prior to detailed design of a selected alternative. An alternative to reinforcing the existing intertie to maintain stability would be to transfer trip one or both Bradley Lake generators when the new intertie trips and allow underfrequency load shedding in the Anchorage/Fairbanks area. Without reinforcement of the existing intertie or transfer tripping of the Bradley Lake units, the Kenai Peninsula and Anchorage areas will become out of step with each other and separate, resulting in system-wide outages. Electrical performance is summarized in Tables 1A and 1B. Figure 1 shows the routes for the alternatives modeled in this study. Secure transfer limits consider both interties in service. PEI-HLY 23-017 (6/96) Final 120293-01/rh 1-5 Modified Existing 115KV Line Parallel Existing 115kV Line Through Portage Parallel Existing 115kV Line with Bird P. Xing BES At Bernice (Modified Existing Line) STIE97 Table 1A: 115kV/ 138kV Alternative Load Flow And Loss Summai Transfer Limit (MW) Post-Contingency Emergency Limits Pre-Contingency New Tie (d) STIE15 STIE97B1 STIE15B EX97138A N/A N/A EX15138A 8.0 N/A 90 7.1 NIA 90 0.933 (f) 190 (e) 90/145 190 (e) 90/145 NIA NIA 0.906 (f) NIA NIA 138 : XT97138A 90/145 XT15138A 90/145 138 | ENS7136C_ | we | a EN15138B 190 (e) 90/145 190 0.905 (f) 1097138E |. 26 P 190 (e) 7 90/145 190 | _ ’ T015138J 5 190 (e) 190 0.918 (f) : BAQ7138D | | 190 (e) | 80/145 | "490 | —_ BA15138B 190 (e) 90/145 (a) - Alternative limit codes below: 1 = Limited by conductor thermal rating (ampacity) 2 = Limited by available generation on the Kenai and transmission losses. 3 = Limited by voltage drop 4 = Limited by system stability concerns (b) - Limit with both interties in service where applicable. (c) - Assumes new intertie out of service, high limit with reactive compensation. 90/145 90/145 90/145 90/145 (d) - Assumes existing intertie out of service, limited by available generation, thermal loading limit for new intertie is 215MW. (e) - Limited to 190MW by available generation / load on the Kenai Peninsula, actual limit by voltage / loading criteria will be near 305MW. (f) - Low voltages occur in the HEA service area for an outage of the Bradley- Soldotna 115kV line, until power output from Bradley Lake is reduced to approximately 60 MW. Note - Conductor thermal limits are based on 75 Deg. C conductor temp, 25 Deg. C ambient with 1.4 mph crosswind, average tarnished surface. TABLE1A.XLS, 5/14/96 1-6 1/10/96 Table 1B: 230kV Alternative Load Flow And Loss Summa: Transfer Limit (MW) Post-Contingency Pre-Contingency Emergency Limits Limited By | Exist Tie New Tie || Emergency | Existing Tie (a) Loss Loss | Limit (b) q — eo Upgrade Existing ladle Line to 230KV N/A . : 1145 Parallel Existing 115kV EX97230A = Line Through Portage EX15230A | ; i 90/145 Parallel Existing 115kV tet 123 ‘ X } 90/145 Line with Bird P. Xing XT15230A 2015 123 , . 90/145 EN97230C 1997 124 . : 90/145 EN15230B 2015 126 2 0.8 2.0 190 (e) 90/145 T097230C 1997 | 125 | 2 1.3 1.3 190 (e) | 90/145 T015230C 2015 125 2 U7 1.3 190 (e) 90/145 i = ee tb = BA97230B 1997 124 24 1.0 190(e) ,|) 90/145 BA15230B 2015 122 2.5 0.9 190(e) | 90/145 (a) - Alternative limit codes below: (d) - Assumes existing intertie out of service, limited by available generation, 1 = Limited by conductor thermal rating (ampacity) thermal loading limit for new intertie is 290MW. 2 = Limited by available generation on the Kenai and transmission losses. (e) - Limited to 190MW by available generation / load on the Kenai Peninsula, 3 = Limited by voltage drop actual limit by voltage / loading criteria will be near 330MW. 4 = Limited by system stability concerns (f) - Low voltages occur in the HEA service area for an outage of the Bradley- (b) - Limit with both interties in service where applicable. Soldotna 115kV line, until power output from Bradley Lake is reduced to (c) - Assumes new intertie out of service, high limit with reactive compensation. approximately 60 MW. : Note - Conductor thermal limits are based on 75 Deg. C conductor temp, 25 Deg. C ambient with 1.4 mph crosswind, average tarnished surface. TABLE1B.XLS, 5/14/96 |-7 1/10/96 : LS SOLDOTNA ( EA) SOLDOQTNA (AEGAT) [rroecr, = = feof ero reson ere | nog Pore | oar | FIGURE 1 1G. /DESIGN.: 0. #: —120293—01 ___ oe | Joe] re ELECTRICAL STUDY —— a dd | ee ee erences isis eee enna adel a= + —| | Re ns _ —————— +} 7 FF er 1.4 ELECTRICAL SYSTEM STUDY SUMMARY Analysis of the system loading and available Kenai generation indicated that there is approximately 156MW available for transfer from the Kenai to Anchorage in the summer and 125MW in the winter, if spinning reserve is maintained on the Kenai Peninsula. If all capacity is used for generation, a maximum of 190MW is available for transfer from the Kenai Peninsula. If Anchorage generation is used to supply the Kenai Peninsula, the summer transfer south would be approximately 47MW with no Kenai generation. This study used the following load levels for the analysis: e Maximum Transfer North in Summer = 190MW e Normal Winter Transfer North = 125MW e Normal Summer Transfer South = 47MW With these load levels, POWER performed load flow and dynamic stability analyses of the alternatives previously described. The results of the studies are summarized in the narrative below and in Tables 1A and 1B on pages 5 and 6. DO NOTHING: The transfer limit (north or south) of the existing line is approximately 70MW, which is the thermal limit of the section of Brahma conductor between Indian and Girdwood. With sufficient Kenai and Anchorage generation on-line, the system steady- state voltages remain very close to the ASCC criteria during outages of most system components studied. Outage of the East-West 230kV submarine cable between Beluga and Anchorage results in significant low voltages in Anchorage, and the impedance of the existing tie limits the use of Kenai generation to help support the Anchorage area. The existing intertie also shows poor stability for Anchorage and the Kenai at transfer levels above 70MW. The stability limit is based on having sufficient additional generator capacity on-line and ready to supply power in the Anchorage area, which is referred to as ‘spinning reserve,’ and transfer tripping at least one Bradley Lake generator within five cycles (0.0833 second) of the occurrence of a fault on the existing intertie. This alternative limits the ability of the IPG members to fully utilize the shared resource at Bradley Lake. The existing tie does not meet ASCC criteria for single contingencies outages. MODIFY THE EXISTING 115KV LINE ALTERNATIVES - Up to 125MW could be transferred on the existing 115kV tie with additional reactive compensation for voltage support (such as shunt capacitors to improve voltage or thyristor controlled series capacitors to reduce the apparent line impedance), realizing that if the line trips, there is a very high probability that the electrical system will become unstable. This would result in system-wide outages and load shedding. A major drawback to continuous loading at levels above 70MW is that the line losses between the Soldotna and University substations PEI-HLY 23-017 (6/96) Final 120293-01/rh 1-9 increase substantially. For the 125MW flows used in the study, the losses increased from 6.9MW to 25MW. Addition of approximately 60Mvar of shunt capacitors to the line near Hope or Portage significantly improves the voltage, such that the line would meet ASCC criteria. Load and stability studies indicate that the shunt capacitors could be split into two units, with 40Mvar at Portage and 24Mvar connected with the Daves Creek SVS to allow the existing SVS to support the voltage. Another option would be to install 60Mvar of shunt capacitors, switched in 20Mvar steps, at Portage to operate in conjunction with a 20Mvar .--Thyristor- Controlled-Reactor-to-control+the voltage+to-near-1.02-per unit: This alternative is not feasible as a stand-alone modification due to the high losses for increased power transfers (25MW for 125MW transfer). Installation of 25 Ohms (40Mvar) of series capacitors on the Daves Creek - Hope 115kV line would also allow increased power transfer while maintaining the ASCC criteria. There is a concern that mechanically switched series capacitors may initiate problems due to subsynchronous resonance (SSR) with the system combustion turbine generators. Industry literature indicates that the use of Thyristor Controlled Series Capacitors (TCSC) will mitigate the possibility of problems due to SSR. It must be understood that this is a new technology and there are only two operational TSCS banks in the United States. This option also suffers from high losses with increased power transfers because the conductor resistance is not affected by the series compensation. This option would require additional engineering studies to completely evaluate the SSR and subsynchronous oscillation possibilities. Industry literature is included in Appendix D of this report. Upgrades of the existing line to 138kV would not significantly improve the line performance since the voltage is only raised 23kV. This alternative is not considered feasible, due to the extensive transformer replacements, and should not be considered further. Upgrade of the line to 230kV would solve the problems of capacity and system stability with the line in-service, but it would only aggravate the stability problems for the loss of the tie line. This alternative will be more expensive, compared to the New Intertie alternatives, because of the need to change out substation transformers at Indian, Girdwood, Portage, Hope, Daves Creek, Summit Lake and Quartz Creek and addition of a 12MVA 230-115kV transformer at Daves Creek to serve Seward. This alternative should not be considered further. NEW 138kV INTERTIE ALTERNATIVES - Analysis of the four 138kV intertie alternatives indicates that each of the assumed routes studied performs in essentially the same manner. No electrical reason was apparent in the studies to prefer one route over another. Although there are subtle differences in the intertie operations, each shows good performance characteristics, and each has the capacity to transfer the projected power to and from the Kenai Peninsula. Thermal conductor capacity with 795kcmil Drake is 215MW at 138kV, which fits well with the maximum available generation capacity on the PEI-HLY 23-017 (6/96) Final 120293-01/rh 1-10 Kenai of 190MW in the summer (88% of capacity). For the winter transfer of 125MW, the conductors would be loaded to 58% of capacity. Each of the alternatives with submarine cable (Enstar, Tesoro and Beluga) require moderately-sized shunt reactors at the cable terminations to hold the voltage below 1.05 per unit with the line unloaded. With the cables loaded, reactors can be switched off-line, and the cable capacitance can be used to support the system’s reactive power needs. The route which parallels the existing line (overhead transmission only) does not require reactors. The Bird Point crossing of Turnagain Arm reduces the line length for the alternative that parallels the existing line by about 25 miles. This reduces losses and improves the voltage performance of the alternative. This alternative should be considered further to determine whether the challenges of the physical crossing (and maintenance issues) outweigh the additional losses and construction costs for the route through Portage. The new 138kV interties significantly improve stability on the Kenai, and again, they perform very comparably. The most significant disturbances with the new intertie in place for stability were a fault and tripping of the Bradley-Soldotna line and a fault and trip of the new intertie. If the fault and trip of the Bradley-Soldotna line results in a trip of both Bradley Lake units, the 120MW energy deficit results in significant load shedding in Anchorage. If only one Bradley Lake unit is tripped, the system remains stable with the new intertie. For a trip of the new intertie, the impedance of the existing intertie presents significant problems for the transient power flow and results in an out-of-step condition on the existing intertie, which then trips. This results in significant underfrequency load shedding in Anchorage, and the Kenai experiences high frequencies. There are two methods to resolve this problem. One method is to transfer trip one Bradley Lake unit with the new intertie to prevent the out-of-step condition. This method relies on sufficient spinning reserve in Anchorage to support the 60MW deficit. The other method is to switch in series compensation on the existing intertie to reduce the apparent impedance and allow a higher level of emergency power flow. Further analysis of the series compensation alternative will be required to determine the critical switching parameters and the amount of compensation to be switched versus continually on-line. The stability studies indicate that adding 24Mvar to Daves Creek SVS and series compensating the line to 25% with an additional 20Mvar shunt capacitor for voltage support, significantly improves stability for loss of a second intertie. This modification would not be feasible for normal operation, again, due to the high losses. NEW 230kV INTERTIE ALTERNATIVES Analysis of the four 230kV_ intertie alternatives indicates that each of the assumed routes studied performs essentially the same. The Enstar, Tesoro and Beluga alternatives each require large shunt reactors at each end of the submarine cable to counter the cable capacitance. The thermal limit for PEI-HLY 23-017 (6/96) Final 120293-01/rh 1-11 795 Drake at 230kV is 358MW. Maximum summer loading of 190OMW would use 53% of the line rating, while the winter transfer maximum of 125MW would only use 35% of the rating. This indicates that the 230kV alternatives would be under-utilized unless additional generation resources are developed on the Kenai Peninsula. The Enstar, Tesoro and Beluga routes all require large reactors to remain on-line with the lines loaded to the maximum available transfer of 19OMW. This indicates that the circuits are under-utilized. While the route paralleling the existing line does not require reactors on-line during heavy load transfers, reactors will be required when the circuit is unloaded —or lightly loaded. Stability performance of the 230kV alternatives are similar to the 138kV_intertie performance. All of the 230kV alternatives require significantly more equipment than the 138kV alternatives. BATTERY ENERGY STORAGE (BES): Studies of the BES alternatives were primarily dynamic stability studies. Installations were considered at both the Bernice Lake and International substations. BES units are able to produce and absorb real and reactive power quickly and remain on-line (up to 20 minutes) long enough to ramp down or start generation. Installation of a 40MW BES at Bernice Lake improves the stability of the Kenai Peninsula and will allow a reduction of spinning reserve on the Kenai. It does not substantially improve the stability for Anchorage, especially if the intertie is opened. Installation of a 4OMW BES in Anchorage improves the system stability, especially when the existing intertie is opened, as it provided a portion of the power deficit. Installation of the BES generally enhances system stability, but it will not substantially increase power transfer opportunities without improvements on the existing intertie to reduce losses and correct low voltages. PEI-HLY 23-017 (6/96) Final 120293-01/rh 1-12 II. ELECTRICAL SYSTEM STUDIES 2.1 GENERAL The focus -of the electrical -system study was -to-evaluate the Railbelt system when increased power transfers are made to and from the Kenai Peninsula. Generation resources on the Kenai Peninsula consist of the Bradley Lake hydro, Bernice Lake combustion turbines, Soldotna combustion turbine and Cooper Lake hydro. The IPG desires to increase power flows between the Kenai and Anchorage areas to provide lower cost power (economic dispatch), reduce the need for ‘spinning reserve’ in Anchorage and the Kenai, and improve the dynamic stability of the Railbelt transmission system. To achieve these goals, two primary options were considered. 1. Increasing the transfer capacity of the existing 115kV intertie from Soldotna through Daves Creek and Portage to Anchorage. The transfer capacity of the existing intertie can be increased through reconductoring, increasing the voltage, adding shunt and/or series reactive compensation, and installing battery energy storage (BES) on the Kenai Peninsula or Anchorage, or both locations. (Alternatives 1 and 6) 2. Constructing a new intertie between the Kenai Peninsula and Anchorage. This would allow increased power transfers and provide a second link between the areas. (Alternatives 2, 3, 4 and 5) The existing and alternative systems were analyzed with projected loads for the years 1997 and 2015. Each upgrade alternative was studied for standard voltage levels of 138kV and 230kV, with the exception of the Do Nothing and BES alternatives. The new intertie alternatives were modeled as express transmission lines between the Kenai Peninsula and Anchorage with no taps to distribution substations. Electrical performance was based on voltages, line loading, losses, and dynamic stability criteria. Power transfer scenarios studied were: Maximum transfer from the Kenai to Anchorage with winter 1997 load Maximum transfer from the Kenai to Anchorage with winter 2015 load Maximum transfer from the Kenai to Anchorage with summer 1997 load Maximum transfer from Anchorage to the Kenai with summer 1997 load PEI-HLY 23-017 (6/96) Final 120293-01/rh I-14 Power transfer from the Kenai Peninsula to Anchorage is limited to the difference between the generation on the Kenai Peninsula and the load, additional line losses and any spinning reserve on the Kenai Peninsula. Table 2 shows the maximum amount of power available for transfer without ‘spinning reserve’ on the Kenai. In most cases for this study, some spinning reserve was left in the Soldotna generator for the load and stability studies. Table 2: Maximum Available Power for Transfer from the Kenai to Anchorag Kenai System (MW) -Maximum |-- Projected Additional Spinning Available Generation Load Losses Reserve Transfer Summer 1997 247.8 Summer 2015 | 247.8 Winter 1997 | 247.8 Winter 2015 247.8 Even though there is approximately 190MW in summer and 150MW in winter of available power to transfer north, practical operation of the system will reduce the flows. For the summer system power flows, the transfer is reduced to approximately 157MW, and the winter transfer is reduced to about 125MW. For the 1997 cases, the Bernice Unit 2 was left off-line. To put this unit on-line, larger (more economical) generators in the Anchorage area would have to be taken off-line or backed off to allow the power to flow from the Kenai Peninsula. For this study, an effort was made to model generation as it would most likely be scheduled during operation. Table 3 reflects the typical generation schedules used for the load flow studies. Table 3: Scheduled Power for Transfer from the Kenai to Anchorage Kenai System (MW) Year Generation | Projected Additional Spinning Available Load Losses Reserve Transfer Summer 1997 (1 229.8 Winter 1997 (1 229.8 Winter 2015 247.8 (1) Bernice Lake Unit 2 is off-line, as it would be smaller than any remaining units in Anchorage that would have to be taken off-line to allow the power to flow from the Kenai. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-2 2.2 SYSTEM STUDIES CRITERIA AND ASSUMPTIONS Chugach Electric Association (CEA) provided the Railbelt system databases for the years 1997 and 2015 in Power Technologies Incorporated PSS/E format. The databases included planned improvements and projected loads. CEA also provided the dynamic stability databases complete with models of the static var compensators (SVCs), battery energy storage (BES), superconducting magnetic energy storage (SMES), generators, exciters and governors. These models were modified to include the proposed improvements for-each of the study alternatives. Criteria Power flows were analyzed according to the following criteria: e Alaska Systems Coordinating Council (ASCC) planning criteria #1 through #5. Please refer to the planning criteria document in Appendix A of this Volume. e “Pre-Contingency Secure” rating is the maximum amount of power that can be transferred with the system intact and still withstand a N-1 contingency without loss of load and staying within the ASCC criteria. e “Pre-Contingency Emergency” is the maximum steady-state power that can flow with the system intact and have the system stay within the ASCC criteria. e “Post-Contingency Emergency” is the maximum steady-state power that can flow with the system in a N-1 contingency and have the system stay within the ASCC criteria. e New transmission interties would be 795kcmil ACSR Drake conductor or equivalent for cable. e New transmission interties would be either 138kV or 230kV (115kV is excluded). Generation for the alternatives was scheduled according to the following criteria: e Total Bradley Lake generation capacity is 1ZOMW. e When reducing generation in the Anchorage area, machines will be taken off-line, starting with smaller capacity units and working up to larger units. e Beluga Units 6 and 7 are combined-cycle combustion units that feed the Beluga Unit 8 steam turbine. Therefore, any reductions on either Unit 6 or 7 must be accompanied by a proportional reduction on Unit 8. e AML&P Plant, 2 Units 5 and 7 are combined cycle combustion units which feed the Plant 2 Unit 6 steam turbine, reductions on either Unit 5 or 7 must be accompanied by a proportional reduction on Unit 6. e When reducing generation in Anchorage, reductions will be generally split between CEA at Beluga and AML&P at Plant 2. e General practice is to keep at least one combustion turbine or at least 25MW of hydro generation output on-line on the Kenai Peninsula. e Generation and load will not be adjusted in the Fairbanks area for this study. PEI-HLY 23-017 (6/96) Final 120293-01/rh -3 Assumptions For this study the following assumptions were used in the analysis of the alternatives: e Fairbanks Area is defined as GVEA and FMUS service areas. e Anchorage Area is defined as the AML&P, MEA and the CEA service areas out to Hope. e Kenai area is defined as the HEA, SEA and CEA service area to include Daves Creek. e -Transfers are defined as the flows on the existing intertie between Daves Creek and Hope and the flow on the new intertie. e The swing bus for power flows is Beluga Unit 3. Thermal limits for overhead conductors are based on ampacities from the Westinghouse Transmission and Distribution book which are based on 75°C conductor, 25°C ambient and 1.4 mile per hour wind speed. e Ampacity limits for underground/submarine cables were calculated and provided by Power Delivery Consultants for the specified cables and insulations. Figures 2 through 5 illustrate the system loading, generation and target power transfer levels. Power transfers for each case may be slightly lower or higher based on the system voltages and line loading. Load and generation schedules for the analysis are included in Volume II of this report. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-4 GENERATION 40MW* AT DOUGLAS ncludes Existing an New Interties 105MW* ARRIVES AT ANCHORAGE id 123MW* TRANSFERRED 229.8MW “Values are approximate FIGURE 2: AREA LOAD, GENERATION AND TRANSFERS WINTER 1997 TI-5 GENERATION _| FAIRBANKS AREA 79MW* AT DOUGLAS 524.5MW New Interties 82MW* ARRIVES AT ANCHORAGE Includes Existing and 125MW* TRANSFERRED 247.8MW “Values are approximate FIGURE 3: AREA LOAD, GENERATION AND TRANSFERS WINTER 2015 II-6 GENERATION FAIRBANKS AREA ANCHORAGE AREA 173MW* ARRIVES AT ANCHORAGE id Includes Existing an New Interties 181MW* TRANSFERRED “Values are approximate FIGURE 4: AREA LOAD, GENERATION AND TRANSFERS SUMMER 1997 - MAXIMUM TRANSFER FROM KENAI GENERATION FAIRBANKS AREA ANCHORAGE AREA 49MW* TRANSFERRED includes Existing and New Interties 44MW* RECEIVED KENAI AREA 3.8MW (Tesoro) “Values are approximate FIGURE 5: AREA LOAD, GENERATION AND TRANSFERS SUMMER 1997 - TRANSFER TO KENAI II-8 2.3 LOAD FLOW ANALYSIS Load flow studies were performed by taking the provided base cases and increasing the power transfer to the 70MW transfer limit (determined in previous studies) with the 1997 and 2015 projected loads. The voltages, line loading and losses for the normal system under steady-state conditions were recorded. Each of the alternative systems described in Section 1.2 were then added to the computer . database and the-system-generation adjusted to produce the-desired power transfers for both the 1997 and 2015 winter cases. For each transmission alternative, various intermediate cases were analyzed to determine transformer taps and reactive compensation requirements to achieve the desired steady-state power transfer. After the system was adjusted to provide operation within the study criteria, voltages, line loading and losses were recorded. The load flow cases were then prepared for dynamic stability analysis to determine the ability of the system and additional equipment required to maintain service after a power system disturbance. Summer 1997 cases were analyzed with maximum power flow from the Kenai to Anchorage (summer 1997), since operations personnel indicate that this transfer condition often results in major system outages upon loss of the existing intertie. For these cases, all of the Kenai generation was put on-line with little spinning reserve. Summer 1997 cases were run for the transmission alternatives with all power on the Kenai provided from Anchorage over the interties. For this analysis, only the Tesoro generation was on-line on the Kenai Peninsula. Case descriptions for all of the load flow runs and selected Load Flow Results Diagrams are included in Volume II of this report. Following is the load flow analysis of each Alternative. It was noted in the initial load flow runs that several buses were consistently below 0.95 per unit voltage. These buses were Phillips 24.9, Bernice T1 24.9, Ft. Greely 24.9, Ft. Greely 4.16, Pump #9 24.9 and Jarvis 138. The low voltage buses are outside the scope of this contract, which is focused on the transmission system (69kV and above). Voltage for the 24.9kV and 4.16kV buses could be improved with the installation of voltage regulators, LTCs or by adjusting the power transformer de-energized tap changer to boost the voltage. The Jarvis 138kV bus is in the transmission class, but it is in the Fairbanks area, and the voltage is controlled by the Healy and Gold Hill SVS systems. Voltage on this bus could be improved with the addition of a shunt capacitor near the load. This bus was also considered to be outside the concern of this contract. These buses are not considered further and are not included in the summaries. The low voltages on these buses were not considered in the limitations of the intertie alternative analysis, as they require voltage correction other than reinforcement of the Anchorage-Kenai transmission system. PEI-HLY 23-017 (6/96) Final 120293-01/rh I-9 ALTERNATIVE 1 - DO NOTHING: The existing intertie is operated at 115kV, is approximately 146 miles long and connects the University and Soldotna substations. It is tapped to distribution substations at Indian, Girdwood, Portage, Hope, Summit Lake (fall 1995), Daves Creek, Lawing and Quartz Creek. The majority of the conductor is 556.4kcmil ACSR Dove. This conductor has a thermal rating of 730 amperes, which is equivalent to a rated power flow of 145MVA. -However; there-is a 4.55-mile section of -203.2kcmil Brahma conductor between Indian and Girdwood that is rated at 360 amperes (equivalent to 72MW). The existing line is currently limited to a continuous 70MW transfer by voltage, line thermal loading and stability concerns. Up to 115MW can be transferred in emergency conditions before the voltage drops below the 0.95 per unit criteria. This would result in a 164% overload of the Brahma conductor. Each utility generally establishes their emergency line overload criteria based on ambient temperatures, expected duration of the overload and the calculated loss of conductor strength. If a 125% overload is allowed for a short time, the “Brahma” section of line will limit the existing 115kV tie to approximately 90MW. It should be noted, however, the 4.55 miles of Brahma conductor is scheduled to be changed out for 556.4kcmil in the near future, which will increase the emergency transfer limit to 11SMW. Line performance for steady-state operation is tabulated in Table 4 below. At power transfers greater than 115MW, the voltage drops below the 95 percent limit at Seward, Hope, Portage and Girdwood. Table 4: Alternative 1 - Do Nothing - Load Flow and Loss Summary Post-Contingency Emergency Limits a obi New Tie oe se New Tie Ampacity / 1997 70 Stability / 90/115 | 90/115 Voltage Drop | Ampacity / 70 Stability / 7.1 N/A 90/115 }| 90/115 N/A Voltage Drop CEA personnel indicate that the Anchorage and Kenai system stability is so seriously impacted by faults on this line that the power transfer is reduced to near zero during inclement weather and when working near energized conductors during maintenance to minimize the impact of a loss of the tie line. The existing route traverses avalanche chutes and areas of high wind/ice loading. Past outage data for this line indicates numerous outages. There have been significant improvements on this line in the last few years, which should improve the reliability. No recent outage data was available for this study to Pre-Contingency Existing 115KV Line PEI-HLY 23-017 (6/96) Final 120293-01/rh I-10 indicate the reliability since the upgrades. However, operations personnel indicate that they have seen a significant improvement in the reliability of this tie line. ALTERNATIVE 1A - UPGRADE THE EXISTING LINE TO 138KV: Upgrading the existing 115kV line to 138kV. would only slightly increase the power transfer flow above the transfer that would be achieved at 115kV. This alternative would require reinsulation of most of the line, replacement of the substation transformers and possibly circuit switchers-and circuit-breakers at Indian, Girdwood, Portage, Hope, Daves Creek and Quartz Creek, installation of a 12MVA 138-115kV transformer at Daves Creek to serve Soldotna and Lawing. Power flow cases were not run for this alternative to establish benefits of the voltage upgrade. The equipment costs associated with an upgrade to 138kV are perceived to be uneconomical compared to the minimal additional power transfer capability it would add. This alternative was not considered further. ALTERNATIVE 1B - UPGRADE THE EXISTING 115KV LINE WITH SHUNT COMPENSATION: Upgrading the existing 115kV line with additional 60Mvar of shunt capacitors to support the voltage would increase the steady-state transfer capacity of the line to approximately 125MW. The thermal limit of the 556.4 Dove is 145MVA. Adding the capacitors in 20Mvar banks at several locations (Indian, Portage, Daves Creek) along the line would not significantly reduce line losses when compared to adding a single 40Mvar bank at Hope (or Portage) with a 24Mvar bank added to Daves Creek. The additional capacitors could be also be added as three 20Mvar switched capacitor units at Portage, in conjunction with a 20Mvar thyristor controlled reactor (TCR) to provide more stable voltage control. With the 556.4 Dove conductor, the losses on this line are approximately 26MW, for a flow of 122MW. This means that 35% of the additional SSMW of generation on the Kenai would be expended in losses. Table 5 summarizes the performance of this alternative for the load years 1997 and 2015. The emergency limit of the line would be about 145MW, due to voltage drop. Shunt capacitors were adjusted on the buses from University to Hope in varying sizes throughout the N-1 studies. It was determined that approximately 60Mvar located at either Hope or Portage would be required to allow a short duration transfer of about 125MW over the existing line. PEI-HLY 23-017 (6/96) Final 120293-01/rh Ih-11 Table 5: Alternative 1B - Add Shunt Capacitors - Load Flow and Loss Summary 5 Post-Contingency Pre-Contingency Emergency Limits Secure Exist Tie | New Tie Emerg. Existing Modify Existing Ampacity / 115kV Line Kenai Gen. with 60 Mvar Shunt Compensation ALTERNATIVE 1C - UPGRADE THE EXISTING 115KV LINE TO 230KV: This alternative would upgrade the existing 115kV line to 230kV with 795 Drake conductor. With a transfer of 131MW, the voltages on the line would be within the study criteria. Losses were approximately 9MW. No reactive compensation would be required under maximum loading conditions, but approximately 22Mvar of shunt reactors near each endpoint would be required to hold the voltage within the criteria under light load. Table 6: Alternative 1C - Convert to 230kV - Load Flow and Loss Summary j Post-Contingency Pre-Contingency Emergency Limits Exist Tie | New Tie | Emerg. Existing This alternative would require replacement of the substation transformers, circuit switchers and circuit breakers at Indian, Girdwood, Portage, Hope, Daves Creek and Quartz Creek. It would also require installation of a transformer and associated breakers at Soldotna, along with replacement of the line and installation of shunt reactors. Dynamic stabilility issues will limit the Secure Transfer to 7OMW. Upgrade Existing Line to 230kV The equipment costs associated with this upgrade to 230kV are perceived to be uneconomical (as shown by the cost estimates in the 1987 study). This alternative was not pursued any further. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-12 ALTERNATIVE 1D - UPGRADE THE EXISTING 115KV LINE WITH SERIES COMPENSATION Install 25 Ohms (40Mvar) of series capacitors on the Daves Creek - Hope 115kV line to allow increased power transfer, while maintaining the ASCC voltage criteria. The series compensation would effectively reduce the inductive reactance portion of the line impedance. This bank rating represents 25% compensation of the 115kV intertie from Soldotna to University substations. There is a concern that mechanically switched series capacitors may initiate problems due to subsynchronous resonance (SSR) with the system combustion turbine generators. Industry literature indicates that the use of Thyristor Controlled Series Capacitors (TCSC) would mitigate the possibility of problems due to SSR, but the addition of the thyristor control adds significant cost to the installation. It must be understood that this is a new technology, and there are only two operational TSCS banks in the United States. This option would require additional engineering studies to completely evaluate the SSR and subsynchronous oscillation possibilities. Industry literature is included in Appendix D of this report. In addition to the series compensation, the additional line upgrade/reconductoring as noted in Alternative 1B will be required to increase the thermal rating from 70MVA to 145MVA. This option also suffers from high losses with increased power transfers because the conductor resistance is not affected by the series compensation. This option is not feasible as a “stand alone” alternative since stability issues will limit the existing intertie to 7OMW. ALTERNATIVE 2 - PARALLEL THE EXISTING LINE WITH A NEW 138KV TRANSMISSION LINE: This alternative assumed a new 143.5 mile transmission line at 138kV. It would roughly parallel the existing line route through Portage. The new intertie would not have taps to the existing distribution substations along the route for this analysis. This alternative provides good performance with reasonable losses, as shown in Table 7. No reactive compensation would be required on the new line. All voltages were within the criteria. The normal and emergency transfer is with both lines in service. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-13 Table 7 - Alternative 2 - Parallel Existing at 138kV - Load Flow and Loss Summary Post-Contingency Pre-Contingency Enperueiey Liniia Altemative Year ree Tie | New Tie 90/145 roy pe [oe feme[ ot [Pe fore Line a eeey pel 90/145 ALTERNATIVE 2A - PARALLEL THE EXISTING LINE WITH A NEW 138KV TRANSMISSION LINE WITH A CROSSING AT BIRD POINT: This alternative assumed a new intertie of 118.5 miles of transmission line at 138kV. It would roughly parallel the existing line route but would be routed directly north from the Hope Substation, with overhead construction to a crossing of Turnagain Arm from Snipers Point to Bird Point. Table 8 shows the line performance with 121MW transfers in the winter. Up to 184MW transfers are possible in the summer with both lines in service. The new line can transfer up to 138MW in the summer before reaching the 0.95 per unit minimum voltage. No reactive compensation would be required on the new line with an overhead crossing. All voltages would be within the criteria. Addition of capacitors would increase the emergency transfer capacity of the new intertie. Table 8: Alternative 2A - Parallel Existing at 138kV with Crossing at Bird Point - Load Flo Pre-Contingency Line 138kV Line with Bird P. Xing Electrical performance for a submarine crossing at Bird Point would be similar to the overhead crossing case. However, 10 Mvar shunt reactors would be required at the cable termination points to hold the voltage within the criteria and reduce the reactive current flow. ALTERNATIVE 2B - PARALLEL THE EXISTING LINE WITH A NEW 230KV TRANSMISSION LINE: This alternative is the same as Alternative 2, except the voltage of the new line is at 230kV. Line performance is summarized in Table 9. No reactive compensation would be required on the new line. All voltages would be within the criteria. For a transfer of approximately 125MW, losses would be reduced to 50% of the losses for the 138kV alternative. This line would allow transfer of over 190MW from the Kenai without having the existing line in-service. PEI-HLY 23-017 (6/96) Final 120293-01/rh I-14 Table 9: Alternative 2B - Parallel Existing at 230kV - Load Flow and Loss Summary Parallel Existing 115kV with a New 230kV Line Through Portage iim fo [= fom [ fap | eee This model did not consider any sections of underground. Addition of any significant sections of 230kV underground transmission cable would require reactors to control the voltage. ALTERNATIVE 2C - PARALLEL THE EXISTING LINE WITH A NEW 230KV TRANSMISSION LINE WITH A CROSSING AT BIRD POINT: This alternative is the same as Alternative 2, except the voltage of the new line is at 230kV. Line performance is summarized in Table 10. No reactive compensation would be required on the new line with an overhead crossing. This alternative could transfer all the 190MW of available Kenai generation in the summer without the existing line in- service. Table 10: Alternative 2C - Parallel Existing at 230kV with Overhead Crossing at Bird Point Exist Tie | New Tie | Emerg. || Existing Loss Loss Limit Tie outs Parallel Existing 115kV with a New 230kV Line with a Crossing at Bird Point Since a 230kV submarine crossing is not feasible, to go undersea with this alternative, the cable crossing would have to be stepped down to 138kV and then stepped back up to 230kV at Bird Point. The reactors required would remain sized at 10 Mvar. ALTERNATIVE 3 - ENSTAR ROUTE AT 138KV: This alternative considered a new 138kV intertie line from the Soldotna Substation to the International Substation. The intertie was assumed to have a length of 72.9 miles, with 8.75 miles of submarine/underground cable. The electrical model paralleled the existing line from Soldotna with an overhead transmission line that would cut north at Sterling along the east side of the moose refuge, change to submarine cable across Turnagain Arm, PEI-HLY 23-017 (6/96) Final 120293-01/rh W-15 and 0.25 miles after the landing site, then go back to overhead construction into the International Substation. A 138kV step-up transformer would be required at the Soldotna Substation, and a 22Mvar reactor would be required at each submarine cable termination site to mitigate the effect of the cable capacitance during lightly loaded conditions. As shown in Table 11, line performance is good. This line should be able to transfer the available excess Kenai capacity of 190MW in summer. Table 11: Alternative 3 - Enstar Route at 138kV - Load Flow and Loss Summary ALTERNATIVE 3A - ENSTAR ROUTE AT 230KV: This alternative considered a new 230kV intertie line from the Soldotna Substation to the International Substation. The assumed route and type of construction were the same as Alternative 3, except the voltage class is 230kV. A 230kV step-up transformer would be required at the Soldotna Substation, and a 60Mvar reactor would be required at each submarine/underground cable termination site to neutralize the cable capacitance during lightly loaded conditions. As shown in Table 12, line performance is good. Table 12: Alternative 3A - Enstar Route at 230kV - Load Flow and Loss Summary Enstar PEI-HLY 23-017 (6/96) Final 120293-01/rh ll-16 ALTERNATIVE 4 - TESORO ROUTE AT 138KV: This alternative would require a new 138kV intertie line from the Bernice Lake Power Plant to the Point Woronzof Substation. It would generally parallel the Tesoro pipeline. The electrical intertie model was overhead from the Bernice Lake Power Plant northeast along the Cook Inlet, convert to a four-mile section of underground cable through Captain Cook State Park, return to overhead construction to Point Possession, and change to submarine cable across Cook Inlet to the Point Woronzof Substation. The total line length is 59.5 miles, with 15.9-miles of submarine and 4.0 miles of underground cable. Line performance is good, as shown in Table 13. Table 13: Alternative 4 - Tesoro Route at 138kV - Load Flow and Loss Summary Post-Contingency Pre-Contingency Exist Tie ire ri Loss i 190 oS Se 190 20/145 | 100 | Switched reactors sized at 30Mvar and 10Mvar would be required at the Point Possession Substation to counteract the effect of the cable capacitance. With the line open at Woronzof, 40Mvar would be required to hold the voltage on the line below the 1.05 per unit limit. During lightly loaded operation for summer flows to the Kenai, 30Mvar would be sufficient to control the voltage rise. During heavy winter flows, the reactors could be disconnected to allow the cable to supply vars to the system and reduce the need for var generation. One existing 11Mvar reactor at the Point Woronzof Substation, in addition to a new 30Mvar reactor, could be used to neutralize the capacitance at that end. Additional construction at Point Woronzof to add a third terminal, breakers and relaying/control would be necessary since this is only a submarine cable termination station at this time, with two lines in and out (no breakers). The existing 115kV line from Soldotna to Bernice Lake would not require any upgrades for this alternative. Limited By ALTERNATIVE 4A - TESORO ROUTE AT 230KV: This alternative would be the same as Alternative 4, except the voltage is 230kV. A 75Mvar reactor at the Point Possession Substation and two switched reactors (30Mvar and 40Mvar steps) at the Point Woronzof Substation would be required to counteract the cable capacitance. Line performance is good. This line should be able to transfer all of the 190MW available on the Kenai in summer without exceeding the voltage criteria. Line performance is shown in Table 14. PEI-HLY 23-017 (6/96) Final 120293-01/rh I-17 Table 14: Alternative 4A - Tesoro Route at 230kV - Load Flow and Loss Summary Post-Contingency Emergency Limits Pre-Contingency Alternative ALTERNATIVE 5 - BELUGA ROUTE AT 138KV: This alternative would require a new intertie line from the Bernice Lake Power Plant across Cook Inlet to the Beluga Power Plant Substation. It would be rated at 138kV. The electrical model assumed an overhead transmission line that would run northeast from the Bernice Lake Power Plant along the east side of Cook Inlet, with a four-mile section of underground cable through Captain Cook State Park, return to overhead construction to Gray Cliff, change to submarine cable across Cook Inlet to the North Foreland Substation and return to overhead construction from the North Foreland Substation to the Beluga Substation. The total line length would be 62.5 miles with 21 miles of submarine cable. 20Mvar reactors would be required at the Gray Cliff and North Foreland substations to neutralize the capacitance under load. An additional 40Mvar reactor at the Grey Cliff Substation would be required to switch in under no-load conditions. Table 15 presents the line performance. Table 15: Alternative 5 - Beluga Route at 138kV - Load Flow and Loss Summary i Post-Contingency Pre-Contingency Emergency Limits Alternative Year Limited By Exist Tie | New Tie | Pw = [ono pap a fie ra =] Beluga Route ssw [ae [ee [venom [oe [21 |e [orn] | ALTERNATIVE 5A - BELUGA ROUTE AT 230KV: This alternative assumed the same route as Alternative 5, except the line would be constructed at 230kV. Reactors rated at 90Mvar each would be required at the Gray Cliff and North Foreland substations to neutralize the capacitance. Table 16 shows the line performance results. PEI-HLY 23-017 (6/96) Final 120293-01/rh ll-18 Table 16: Alternative 5A - Beluga Route at 230kV - Load Flow and Loss Summary Post-Contingency Pre-Contingency Emergency Limits = Le [orem ALTERNATIVE 6 - BATTERY ENERGY STORAGE (BES): Under this alternative, BES would be installed on the Kenai Peninsula or in Anchorage, or in both locations to allow increased flows on the existing intertie. The analysis of these installations will be limited to the analysis of the system’s dynamic stability with the BES on-line. Installation of the BES would need to be coupled with Alternatives 1B or 1C to increase power flows, as the BES should reduce the need for spinning reserve on the Kenai and in Anchorage, and generally improve system stability. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-19 2.4 ALTERNATIVE N-1 ANALYSIS In this analysis, the alternatives described above were modified to determine the alternative system response to credible single-contingency outages. Each alternative, except for Alternative 6 - BES, was analyzed for the Winter 2015 case to evaluate areas of low voltage, high voltage and line/equipment loading with the system components listed below outaged. N-1 Component Outages: Soldotna SVC off-line Daves Creek SVC off-line Soldotna Unit 1 off-line Point Mackenzie - Woronzof 138kV submarine cable open East Terminal - West Terminal 230kV submarine cable open Beluga Unit 7 and the portion of Beluga Unit 8 generation tripped off-line Bradley Lake Plant generation trips off-line Bradley Lake - Soldotna 115kV line open Existing intertie open New intertie open As noted in section 2.3, page II - 9, there are several buses that exhibit high/low voltage in most cases. Correction of these bus voltages is not within the scope of this study and is therefore not addressed. For the N-1 analysis, we have only identified transmission bus (69kV or above or for transmission system apparatus such as SVSs) voltage criteria violations in the Anchorage and Kenai areas. For all cases with increased power transfer above 70MW, an outage of the Soldotna- Bradley Lake 115kV line results in overloading of the 4/0 ACSR sections of the other circuit from Diamond Ridge through Anchor Point, Kasilof, and Ski Hill to Soldotna. These line sections total about 76 miles of overhead line construction. For the increased power transfer, the emergency thermal limits of these line sections should be evaluated and automatic generation control instituted to reduce the Bradley Lake generator output over a time frame that prevents conductor damage, while maintaining system stability. This time period would need to be long enough to increase the other system generation to replace the Bradley Lake output. The emergency loading duration for these line segments should be based on several steps of ambient temperatures and wind speeds, also keeping in mind that the steel member of the ACSR will not lose mechanical strength as quickly as an all aluminum or all copper conductor. Case descriptions for all of the load flow runs and selected Load Flow Results Diagrams are included in Volume II of this report. The following tables summarize the N-1 load flow analysis of each Alternative. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il - 20 ALTERNATIVE 1 - DO NOTHING: Table 17 - Summary of N-1 Analysis for the Southern Intertie Existing System - 2015 with 70MW transfer from Hope Outage Case Soldotna SVS Off-line Buses Below 0.95 per unit None Buses Above 1.05 per unit Daves SVS - 1.106 Lines Greater Than 100% Loading Daves SVS Off-line Seward 69 - 0.943 Soldotna #1 Off-line Pt. Mackenzie-Pt. Woronzof Off-line None University 230 - 0.941 Soldotna SVS- 1.059 None Daves SVS - 1.098 East Terminal- West Terminal Off-line 41 See Page 1 Appendix B ‘Lowest Voltage at AML&PTap 230 - 0.906 None Homer 69kV - 0.938 Diam Rdg 69kV - 0.946 Soldotna SVS - 1.050 Daves SVS - 1.099 Woronzof.-Mack. 136% of 146MVA rating Daves SVS - 1.086 Bradley Lake-Soldotna Offline None Soldotna SVS - 1.083 Daves SVS - 1.059 Anch Pt-Diam Rdg 102% of 68MVA Rating ALTERNATIVE 2 - PARALLEL THE EXISTING LINE WITH A NEW 138KV TRANSMISSION LINE: Table 18 - Summary of N-1 Analysis for the Southern Intertie Parallel Route 138kV - 2015 with inital 125MW transfer Line Outage Case Buses Below 0.95 per unit Soldotna SVS Off-line Soldotna #1 Off-line Pt. Mackenzie-Pt. Woronzof Off-line Homer 69 - 0.949 Bernice T1 - 0.943 Seward 69 - 0.939 See Page 2 Appendix B Lowest voltage at University 34.5 - 0.939 Buses Above 1.05 per | Lines Greater Than unit Daves SVS - 1.092 Soldotna SVS - 1.090 DavesSVS-1.058 [None Soldotna SVS - 1.054 |None Daves SVS - 1.094 East Terminal-West Terminal Off-line 16 Buses See Pg 3 Appendix B Lowest voltage at University 34.5 - 0.933 Soldotna SVS - 1.055 Daves SVS - 1.099 Woronzof.-Mack. 116% of 146MVA rating Beluga #7 and portion of Beluga #8 Off-line PEI-HLY 23-017 (6/96) Final 120293-01/rh None I-21 Daves SVS - 1.080 None Bradley Lake Units (Both) Off-line Bradley Lake-Soldotna Off- line Diam RDG 69 - 0.946 Homer 69 - 0 0.938 None None Soldotna SVS - 1.084 |Anch Pt 115 - Daves SVS - 1.071 DaimRDG 115 102% of 68MVA Rating None Soldotna SVS - 1.092 Soldotna SVS - 1.077 Daves SVS - 1.092 Existing Intertie Off-line [New Intertie Off-line 60Mvar Capacitor at Hope N-1 analysis was not performed for the Bird Point Alternative 2A. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-22 ALTERNATIVE 2B - PARALLEL THE EXISTING LINE WITH A NEW 230KV TRANSMISSION LINE: Table 19 - Summary of N-1 Analysis for the Southern Intertie Parallel Route 230kV - 2015 with 125MW transfer Lines Greater Than Pt. Mackenzie-Pt. Woronzof Off-line East Terminal-West Terminal Off-line Soldotna SVS - 1.076 Daves SVS - 1.075 None Soldotna SVS - 1.079 Daves SVS - 1.071 Soldotna SVS - 1.070 Daves SVS - 1.060 None Beluga #7 and portion of None Beluga #8 Off-line Bradley Lake Units (Both) Off-line Bradley Lake-Soldotna Off- line Diam RDG 69 - 0.946 ‘Homer 69 - 0 0.938 Diam RDG 69 - 0.918 Anch Pt. 115 - 0.947 Homer 69 - 0.910 Soldotna SVS - 1.094 Daves SVS - 1.067 Line Outage Case Buses Below Buses Above 1.05 per Soldotna SVS Off-line Bernice T1 24.9 - 0.949 [Daves SVS - 1.091 Soldotna #1 Off-line None Soldotnas SVS - 1.064 _|None None Woronzof.-Mack. 101% of 146MVA rating None None Kasilof 115 - Soldotna 130% to 147% of 68MVA Line Ratings (four line sections Soldotna SVS - 1.088 Soldotna SVS - 1.079 None 22 Buses See Sheet 4 Appendix B Lowest Voltage at Hope - 0.827 Existing Intertie Off-line None Qrtz 115 - Daves 115 101% of 145MVA Rating N-1 analysis was not performed for the Bird Point Alternative 2C. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-23 ALTERNATIVE 3 - ENSTAR ROUTE AT 138KV: Table 20 - Summary of N-1 Analysis for the Southern Intertie Enstar Route 138kV - 2015 with 125MW transfer Line Outage Case Buses Below 0.95 per unit unit [Daves SVS Off-line Soldotna #1 Off-line Pt. Mackenzie-Pt. Woronzof Off-line East Terminal-West Terminal Off-line Soldotna SVS Off-line [Bernice T1 24.9 - 0.946 Daves SVS - 1.084 Soldotna SVS - 1.086 ‘None None Buses Above 1.05 per Soldotnas SVS - 1.077 Lines Greater Than 100% Soldotna SVS - 1.092 Daves SVS - 1.055 Soldotna SVS - 1.090 Daves SVS - 1.063 None University 230 - 0.948 Beluga #7 and portion of Beluga #8 Off-line Bradley Lake Units (Both) Off-line = Soldotna SVS - 1.082 [Diam RDG 69 - 0.946 |None Homer 69 - 0 0.938 Woronzof.-Mack. 101% of 146MVA rating None ‘None Bradley Lake-Soldotna Off- line Existing Intertie Off-line New Intertie Off-line 80Mvar added to Universi Soldotna SVS - 1.087 Daves SVS - 1.061 Diam RDG 69 - 0.913 Anch Pt. 115 - 0.942 Homer 69 - 0.905 ‘None Soldotna SVS - 1.098 Seward 69 - 0.915 Soldotna SVS - 1.100 Lawing 0.949 ALTERNATIVE 3A - ENSTAR ROUTE AT 230KV: Table 21 - Summary of N-1 Analysis for the Southern Intertie Enstar Route 230kV - 2015 with 125MW transfer Line Outage Case Buses Below Buses Above 1.05 per Lines Greater Than 0.95 per unit unit 100% Kasilof 115 - Soldotna 130% to 147% of 68MVA Line Ratings four line sections) Pt. Mackenzie-Pt. Woronzof Off-line Daves SVS - 1.069 University 230 - 0.949 [Paves SVS - 1.075 Bradley Lake Units (Both) (Off-line None Daves SVS - 1.051 Daves SVS - 1.075 None None None None None Woron.-Mack. 101%0 146MVA rating Diam RDG 69 - 0.944 |Soldotna SVS - 1.063 [Homer 69 - 0 0.936 PEI-HLY 23-017 (6/96) Final 120293-01/rh I-24 None None Table 21 - Continued Line Outage Case Buses Below Buses Above 1.05 per Lines Greater Than 0.95 per unit unit 100% Bradley Lake-Soldotna Off- {Fifteen Busses Soldotna SVS - 1.087 |Kasilof 115 - Soldotna line See Page 5 Appendix B |Daves SVS - 1.061 130% to 147% of (Lowest V at Anch Pt. 68MVA Line Ratings 115 - 0.924 (four line sections) None Seward 69 - 0.903 Lawing 115 - 0.946 ALTERNATIVE 4 - TESORO ROUTE AT 138KV: Table 22 - Summary of N-1 Analysis for the Southern Intertie Tesoro Route 138kV - 2015 with 125MW transfer Line Outage Case Buses Below Buses Above 1.05 per | Lines Greater Than 0.95 per unit unit 100% Daves Sv Of-ine_fPernie T1 24.9 - 0.949|Soldotna SVS - 1.066 _|None Soldotna #1 Off-line None Soldotnas SVS - 1.066 _|None er el T1 24.9 - 0.949|Soldotna SVS - 1.066 [None Off-line East Terminal-West Woron.-Mack. 101% Terminal Off-line Daves SVS - 1.057 of 146MVA rating Beluga #8 Off-line See ere Ll Off-line Homer 69 - 0 0.937 Bradley Lake-Soldotna Bernice T1 24.9 - 0.948|Soldotna SVS - 1.094 __|Kasilof 115 - Soldotna Offline Diam RDG 69 - 0.918 130% to 147% of AnchPT 114 - 0.947 68MVA Line Ratings Homer 69 - 0.937 four line sections Bernice T1 24.9 - 0.943|Soldotna SVS - 1.075 __|None Soldotna SVS - 1.075 |None Daves SVS - 1.105 Existing Intertie Offline New Intertie Off-line |60Mvar added to Portage PEI-HLY 23-017 (6/96) Final 120293-01/rh I-25 ALTERNATIVE 4A - TESORO ROUTE AT 230KV: Table 23 - Summary of N-1 Analysis for the Southern Intertie Enstar Route 230kV - 2015 with 125MW transfer Line Outage Case Soldotna #1 Off-line Pt. Mackenzie-Pt. Woronzof Off-line East Terminal-West ‘Terminal Off-line Beluga #7 and portion of Beluga #8 Off-line Bradley Lake Units (Both) Off-line Bradley Lake-Soldotna Off- line Existing Intertie Offline [New Intertie Offline 60Mvar added to Portage Buses Below 0.95 per unit Bernice T1 24.9 - 0.945 None None None None None Diam RDG 69 - 0.946 Homer 69 - 0 0.938 Anch Pt. 115 - 0.950 Diam RDG 69 - 0.920 Homer 69 - 0 0.912 None ‘None Buses Above 1.05 per unit Daves SVS - 1.064 Soldotna SVS - 1.063 Soldotna SVS - 1.058 Soldotna SVS - 1.065 Soldotna SVS - 1.064 Daves SVS - 1.058 Daves SVS - 1.059 None Soldotna SVS - 1.098 Soldotna SVS - 1.063 Soldotna SVS - 1.078 Daves SVS - 1.1065 Lines Greater Than 100% Kasilof 115 - Soldotna 130% to 147% of 68MVA Line Ratings (four line sections) None None ALTERNATIVE 5 - BELUGA ROUTE AT 138KV: N-1 analysis was not performed for the Beluga Alternatives, because the Beluga Route had been determined to be technically ‘fatally flawed’ during the concurrent performance of the preliminary design task. Analysis by the transmission engineers and cable manufacturers had determined that the submarine crossing of Cook Inlet at this point was not feasible due to the condition of the Cook Inlet floor and the tidal currents. Correspondence on this alternative is contained in Appendix C for reference. ALTERNATIVE 6 - BATTERY ENERGY STORAGE SYSTEMS (BES): N-1 analysis was not performed for the BES Alternative, because the BES will primarily be effective during transient conditions. Analysis of Alternative 1 - Do Nothing for N-1 conditions indicated low voltages in the Anchorage area. The lowest voltage recorded was 0.8978 per unit on the University 230kV bus. Installation of a BES in Anchorage would obviously be an asset for maintaining acceptable voltages until the system generation could be rescheduled to improve the system voltage. However, this voltage support could also be achieved with the use of much less costly switched capacitors and would meet the voltages specified in ASCC Planning Criteria #2. I-26 PEI-HLY 23-017 (6/96) Final 120293-01/rh When considering the Kenai Peninsula, none of the outages on the existing system resulted in significant voltage dips on the Peninsula. The lowest voltage occurred at the Homer 69kV bus (0.938 per unit). Again, the voltages could be more economically corrected with shunt capacitors. The BES on the Kenai is a detriment when acting as a “brake” against the excess generation capacity. The stability runs indicate that the BES results in extended oscillations of voltage and frequency. 2.5 ALTERNATIVE DYNAMIC STABILITY ANALYSIS Selected power flow models were analyzed using the provided dynamic stability models and the PTI computer software. The objective of the dynamic stability analysis was to establish alternative criteria required to maintain a stable power system when it is subjected to credible single contingency outages. For this study, the dynamic simulations were analyzed for the following system configurations: e The existing 115kV line with a transfer of 7OMW from the Kenai to Anchorage with winter 1997 loading e The existing 115kV line with a transfer of 125MW from the Kenai to Anchorage with winter 1997 loading e Selected intertie alternative systems with 125MW transfer with 1997 or 2015 load cases and new 138kV or 230kV intertie construction e The existing system with Battery Energy Storage installed at the Bernice Lake and/or International substations e Selected alternative systems for maximum transfer from the Kenai to Anchorage during summer 1997 loading conditions e Parallel the existing line alternative system with a transfer of 47MW to the Kenai under 1997 summer loading The above mentioned cases were evaluated for the following events: Trip Beluga 6 and ramp down Beluga 8 (no AC fault) Trip Bradley Lake 1 (no AC fault) Fault on new intertie with subsequent trip of the line Fault at Daves Creek with subsequent trip of the existing intertie to Hope Fault on the Bradley - Soldotna Line with subsequent trip of the line The dynamic stability analysis was performed by taking the base system load flow models and applying the various system disturbances. Plots of the results were analyzed, corrective measures incorporated to improve dynamic response and the modified case was run and analyzed. Dynamic stability results are included in Volume III of this report. Analysis of the alternatives is summarized below. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-27 Ie Existing System Examination of the performance of the existing system has been limited to the 1997 and 2015 winter loading, with 125MW of export (as measured on the Hope line - Portage line). At this loading, the existing 115kV intertie would require, at a minimum, the addition of shunt compensation beyond that presently installed in order to achieve the 125MW level of export with acceptable voltages. While no attempt was made to optimize the size or location of the additional shunt capacitors, it was found that augmenting the capacitive range of the SVC at Daves Creek by the addition of a second 24Mvar capacitor bank-was quite effective (Case W5X). This location has the advantage of allowing mechanical switching of the new bank to be coordinated with the existing Thyristor Controlled Reactor (TCR). All dynamic cases on the existing system were executed with this additional bank in place, since it was required to provide an acceptable initial condition. Clearly, other compensation schemes could be proposed that would also be satisfactory. The Superconducting Magnetic Energy Storage device (SMES) at Plant 2 in Anchorage was taken off-line for most simulations to provide worst-case performances. The dynamic performance of the existing system would be poor for events that result in increased export, either transiently or steady-state, on the existing intertie. This result is not surprising, as the tie, even with the additional 24Mvar of shunt capacitors, is stressed near to voltage collapse in the steady-state operating condition. Trip of the Beluga plant (W5X H1) and fault and trip of Soldotna-Bradley Lake (W5X H4) both result in separation of the tie. (Further discussed below.) Furthermore, trip of any of the new intertie options would result in shifting of the full amount of Kenai-Anchorage exchange to the existing intertie. At the 125MW exchange level, this results in separation of the systems (e.g. W7B HS). Series Compensation of the Existing Intertie Series compensation of the existing intertie would provide substantial benefits. This would be true both for conditions with and without any of the proposed intertie options. A single series bank, representing 25% compensation of the Soldotna- University corridor (25 ohms, 40Mvar) trimmed with a 20Mvar shunt capacitor bank, would allow Anchorage and Kenai to stay synchronized for a wide range of events. Specifically, for the existing system (WSXA Winter 2015, 125MW export, +24Mvar at Daves), all events that would result in the separation of the two subsystems, except trip of the tie itself, remained synchronous (e.g. WSXA H1 vs. W5X H1). As noted above, trip of any of the proposed new interties would result in transferring the total intertie power onto the existing intertie. These cases would also maintain synchronism with the series compensation (e.g. W7BA HS vs. W7B HS). More PEI-HLY 23-017 (6/96) Final 120293-01/rh Il - 28 discussion of series compensation is presented in the discussion of the summer heavy export condition described below. Damping While the series compensation would provide much needed synchronizing -strength between the two subsystems, the dynamics of the transfer of large amounts of power to the tie can result in very large and poorly damped swings (e.g. W7BA HS). Furthermore, the relatively large amount of series compensation has the potential to make control of bus voltages along the intertie difficult. These aspects of the performance of the series compensated system indicate that the addition of thyristor control to the series bank would likely have dramatic benefits. The thyristor control could be applied on all or a portion of the bank. Experience has shown that Thyristor Controlled Series Capacitors (TCSC) have the potential to dramatically improve both the transient synchronizing strength and the damping of interconnected systems. The simple two subsystem configuration of the Kenai-Anchorage interconnection is ideal for this application. It is estimated that interarea oscillations could be completely damped out in two to three swings with a TCSC. The TCSC damping control would need to work in coordination with the existing SVC damping control. The existing SVC damping control is disabled in the cases with the series capacitor in service, so results presented are somewhat pessimistic. 3. Comments on Separation of Kenai and Anchorage As noted in these discussions, several events have the potential to result in the separation of the Kenai and Anchorage systems. In general, the machine-swing transients vary considerably between the different cases. However, the ultimate power/load balance in the two separated subsystems would be essentially the same following separation. Specifically, when the export from the Kenai would be 125MW, Anchorage would be short about 120MW (considering losses) and the Kenai has about 125MW excess. Without further corrections, the Anchorage area would experience a relatively severe underfrequency condition of about 59.4Hz. While Under Frequency Load Shedding (UFLS) would not actually occur for the cases examined, this condition would come very close to causing load shedding (e.g. W5X H3). If the subsystems were to separate due to trip of the Beluga plant (which happens for the existing system without series compensation), the Anchorage system would be short about 240MW (W5X Hl). A large amount of underfrequency load shedding would occur in this case. The Kenai area experiences unacceptably high overfrequency (about +1.9Hz), which would cause the trip of the Soldotna unit (discussed further below). PEI-HLY 23-017 (6/96) Final 120293-01/rh Il-29 While the system stability analysis for this generation / load schedule did not result in load sheding upon seperation of the Anchorage-Kenai systems at 125MW of load, other generation / load mixes could result in load shedding in Anchorage. It must be kept in mind that the systems that In addition, a fast transfer trip of one or both of the Bradley Lake units is required to match the Kenai generation and load upon system seperation. Under conditions where the system would remain synchronous, loss of 120MW of generation (e.g. 2 Bradley Lake or 2 Beluga units), would not result in UFLS (e.g. W7B Hl). 4. Energy Storage Providing energy storage in the Anchorage area, either from SMES or BES, would improve the system performance in two ways. First, for transients that would result in increased power flow over the Kenai- Anchorage intertie(s), the injection of MW into the Anchorage area would result in reduced stress on the interties. For one case studied (W5I H1 winter 2015, existing system, 125MW export, +24Mvar at Daves Creek - trip of Beluga plant), the injection of 40MW for up to 20 minutes from the International BES would prevent system separation and allow other generation to be brought on-line. Secondly, the energy storage devices would benefit the power balance following a variety of disturbances. For disturbances that would result in separation of the two subsystems, the 4OMW BES (or SMES) in Anchorage would reduce the severity of the underfrequency condition. For the winter 2015 125MW export condition, the minimum frequency experienced would be about 59.5Hz (WSI H3), whereas, without the BES, the minimum frequency would be about 59.4Hz (W5X H3), which is marginal with respect to the UFLS settings. The BES modeling for International and Bernice Lake was approximated to a straight open-loop on-off control in which the device was forced to maximum MW output immediately following trip of the Beluga unit. More sophisticated control would likely be used, but this approach bounds the possible performance benefits. It is worth noting that injection of power at the Bernice BES would tend to aggravate the synchronizing problem. Thus, trip of Beluga would cause separation of the two systems connected only by the existing intertie, even with series compensation added, when the Bernice BES tries to help the power/load unbalance in Anchorage (WS5I H6A). In the Kenai area, with loss of the new intertie at 12S5MW transfer, the overfrequency condition (with no plant trips) would be limited to about 61.4Hz (simple open-loop power control was used here as well). This compares favorably with a maximum of PEI-HLY 23-017 (6/96) Final 120293-01/rh Il - 30 about 61.9Hz without the 40MW BES at Bernice Lake. This latter condition would cause the Soldotna unit to trip, whereas it would not trip with the BES. For conditions under which the two subsystems remain synchronous, the BES would improve the power/load balance, reducing the depth of the underfrequency excursion. Conditions under which the system has less spinning reserve, i.e. when one or more BES is being used to provide spinning reserve, would behave quite differently. 5. Intertie Options In this stability study, eight different intertie options were considered. As the case matrix table shows, many simulations were executed on the Enstar 138kV intertie option (W7B and W7BA). This option was chosen because it appeared to have greater cost and reliability benefits compared to the other options. In practice, the similar impedance characteristics of the different options mean the dynamic performance of each different option will be very similar. For the conditions studied, no particular intertie option demonstrated performance that was sufficiently different to distinguish it as either a clearly more desirable or less desirable option than the other options. In general, trip of the new intertie is the most severe case. Performance for trip of the new intertie is mostly dictated by the amount of reactive compensation on the old intertie. The 138kV intertie options cause somewhat less stress on the old intertie when tripped than the 230kV options. This can be observed in the depth of the voltage swings (W7BA HS vs. W7FA HS). Changes in other external conditions, such as series reinforcement of the existing intertie, addition of energy storage, and plant tripping logic all prove to be much more important considerations in the system performance. 6. Summer 1997 Limited testing of the Enstar 138kV reinforcement was made for the summer 1997 system. The existing 115kV intertie was reinforced with the series/shunt additions discussed above (S7BA). The export from Kenai was set at 164MW, which represents an extreme condition. Very little generation is on-line in the northern subsystem. Trip of the new intertie at this very heavy level of transfer would result in separation and trip of the existing intertie as well (S7BA H5). With very little generation on-line in the resultant northern subsystem, massive disruption would occur. If one of the Bradley Lake units were to be transfer-tripped along with the new intertie, the two subsystems would remain synchronous and experience a minimum frequency of about 59.4Hz before recovering to about 59.6Hz after 5 seconds (S7BA HSA). PEI-HLY 23-017 (6/96) Final 120293-01/rh Il- 31 In order to maintain synchronism following trip of the new intertie at this very heavy transfer level, additional compensation of the existing 115kV intertie would be required. When a second series/shunt bank (25 ohms series and 20Mvar shunt) is added on the Girdwood-Indian line at Indian (S7BB), the reinforcement would allow the trip of the new intertie without causing the existing intertie to trip (S7BB HS). The voltage swings for this case would be relatively severe, which suggests that further refinement of the reinforcement would be desirable. Nevertheless, this case demonstrates that the existing intertie could be reinforced in a manner so that it could handle the post-contingency flow for the 164MW export case. Of course, this post- - contingency condition-would result in flows which exceed the thermal rating of the existing line (145MVA) by about 10% to 20%. 7. Conclusions e No new intertie option can be judged to be significantly preferable to another, based on the dynamic performance observed in the cases studies. In general, the 138kV options appear to have very slightly better dynamic’ performance, but the difference does not appear to be sufficient to warrant substantial consideration. Other considerations, such as capital cost, reliability, environmental impact, maintainability and losses should dictate selection of the new intertie route and voltage. e Reactive compensation of the existing 115kV intertie would be required to allow the full benefits of the new intertie to be realized. Without reactive compensation of the existing line, faults on any new intertie would require transfer trip of one of the Bradley Lake units. e Series-compensation of the Soldotna-Quartz line, coupled with selected addition of shunt compensation, would greatly improve the performance of the system; either with or without a new intertie. A series bank of 25 ohms (40Mvar) and a shunt bank of 20Mvar on line would produce good results at 125MW of export. Two series banks of this size and two shunt banks of 20Mvar each would be needed to give adequate results for the severe summer 164MW export condition. The exact level, siting and control of the compensation needs to be studied further. It is estimated that thyristor control of the series bank or banks would be desirable to refine the stated compensation sizes and performance requirements to further improve the performance and raise the stability limit. e Faults south of Soldotna, specifically ones on the Bradley Lake-Soldotna line are very severe with respect to the stability of the Bradley Lake units. Transfer trip of one of the units at Bradley Lake would be required, regardless of the new intertie option. It is estimated that reinforcement of the circuits between Soldotna and Bradley Lake PEI-HLY 23-017 (6/96) Final 120293-01/rh Il - 32 with series compensation would improve the stability of this portion of the system. However, it would be unlikely that both Bradley Lake units could survive the Bradley Lake-Soldotna fault and trip when they both would be operating at 6(0MW, regardless of the amount of reactive compensation. e BES helps the dynamic performance of the system. In particular, BES at International and Bernice Lake would provide some significant benefit when the two subsystems separate. Under some conditions (though in none of the cases run in this study), the BES in the Anchorage area would probably represent the difference between load -shedding occurring and not-- In the-Kenai area, the BES would help moderate the overfrequency condition which follows separation. In the cases run, the BES at Bernice Lake would reduce the overfrequency by about 0.5Hz and prevent the tripping of the Soldotna unit. When the two subsystems were kept synchronous, the benefits of the BES were not so dramatic. Improvement in the total system power balance would be achieved, so that frequency excursions would be reduced. In one case (trip of Beluga with only the existing 115kV intertie in service), the BES at Bernice Lake degraded the stability of the system, so that the otherwise stable system separated. This adverse affect could be avoided by smarter control of the BES than was used in these simple simulations. e SMES in the Anchorage area should provide similar performance to that from the BES, provided corrective actions could be be taken before the SMES exhausts its stored energy. PEI-HLY 23-017 (6/96) Final 120293-01/rh Il - 33 APPENDIX A ASCC PLANNING CRITERIA ALASKA SYSTEMS COORDINATING COUNCIL An association of Alaska's electric power systems Promoting improved reliability through systems coordination ASCC PLANNING CRITERIA for the reliability of interconnected electric utilities May 1991 L | ALASKA SYSTEMS COORDINATING COUNCIL ASCC PLANNING CRITERIA FOR THE RELIABILITY OF INTERCONNECTED ELECTRIC UTILITIES The Alaska Systems Coordinating Council (ASCC) is an association of Alaska’s electric power systems promoting improved reliability through systems coordination-and an affiliate member of the North American Electric Reliability Council (NERC). In August, 1990, the ASCC established a Reliability Criteria Subcommittee composed of representatives of the ASCC members in Alaska’s Railbelt region. The primary task of that Subcommittee was to complete efforts to develop, formulate in writing, and submit to ASCC for approval, coordinated interconnection planning and operating reliability criteria. The ASCC PI * C : : fe | R li t ili " f I % pi ted El : U ili : were prepared for use by the ASCC members in planning and designing generation and transmission network facilities of the interconnected Railbelt utilities. In concert with the planning policies of NERC, the overall framework was provided by the NERC Planning Guides adopted by the NERC Engineering Committee in 1989 that describe good practices for bulk electric system planning. Individual ASCC planning criteria corresponding to the Guides were then developed specifically for the Alaskan interconnected bulk power system. The criteria provide guidance to the utilities in evaluating electric system performance over the planning horizon and provide requirements and recommendations to be considered in planning and designing additions and modifications. Application of the criteria will promote the reliability of the bulk power system of the interconnected electric utilities of Alaska. Included herein are: NERC Planning Guides and corresponding ASCC Planning Criteria .... Page 1 The ASCC Planning Criteria ....... eed nie enls aaa anal ade del Page 2 NERC Terms and Definitions ........... iets Page 17 Recommended by Reliability Criteria Subcommittee: February 19, 1991 Adopted by the Alaska Systems Coordinating Council: April 4, 1991 North American Electric Reliability Council Planning Guides These Planning Guides describe the characteristics of a reliable bulk electric system. They are intended to provide guidance to the Regional Councils, Subregions, Pools, and/or the Individual Systems in planning their bulk electric systems. ° To the extent practicable, a balanced relationship is maintained among bulk electric system elements in terms of size of load, size of generating units and plants, and strength of interconnections. Application of this guide includes the avoidance of Excessive concentration of generating capacity in one unit, at one location or in one arca, Excessive dependence on any single transmission circuit, tower line, right-of-way, or transmission switching station; and Excessive burdens on neighboring systems. ° The system is designed to withstand credible contingency situations. ° Dependence on emergency support from adjacent systems is restricted to acceptable limits. ° Adequate transmission ties are provided to adjacent systems to accommodate planned and emergency power transfers. ° Reactive power resources are provided which are sufficient for system voltage control under normal and contingency conditions, including support for a reasonable level of planned transfers and a reasonable level of emergency power transfer. ° Adequate margins are provided in both real and reactive power resources to provide acceptable dynamic response to system disturbances. © _ Recording of essential system parameters is provided for both steady state and dynamic system conditions. ° System design permits maintenance of equipment without undue risk to system reliability. ° Planned flexibility in switching arrangements limits adverse effects and permits a ° Protective relaying equipment is provided to minimize the severity and extent of system disturbances and to allow for malfunctions in the protective a system without undue risk to system reliability. ° Black start-up capability is provided for individual systems. 9° Fuel supply diversity is provided to the extent practicable. (NERC Planning Guides as approved by NERC Engineering Committee on February 28, 1989) ASCC Planning Criteria Criteria #20 xxx Criteria #3 Criteria #40 #x% Criteria #5 9 xxx Criteria #6 Criteria #7 Criteria #8 Criteria #9 Criteria #10 Criteria #11 Criteria #12 fara, lly we Fr eae! ete FP cm. a ASCC Planning Criteria #2: Contingencies Additions to the interconnected system shall be planned and designed to allow the interconnected system to withstand any credible contingency situation without excessive impact on the system voltages, frequency, load, power flows, equipment thermal loading, or stability. _ Requirements The following contingencies shall be used for planning and design of the interconnected system: As Single Contingency: 1.1. Fault on any line end, assuming that the primary protection removes the faulted line section and has one unsuccessful reclose, if appropriate. 1.2. Loss of any single transformer or line. 13. Starting or loss of any generator or static Var system. 1.4. Acceptance or loss of a large load; e.g. that load being carried on an intertie or major load center. . 1.5. Loss of any substation bus section. Multiple Contingency: Tequires the operation of the back up telay scheme to remove th section of line. Recommendations approved i All facilities should remain below their emergency rating following any Singlesar umutnpta contingency occurrence. 2. All testing and verification studies should be performed at peak and off-peak load and generation levels. ASCC Planning Criteria #2, Page 1 of 2 . 4 There should be no loss of load on a system for the more common single contingency disturbances originating on other systems, except for load shedding to stabilize extreme frequency decay which would cause uncontrolled area-wide power interruptions. The uncontrolled loss of load is unacceptable even under the most adverse credible disturbances. . During all excursions subsequent to the occurrence of any single contingency, the following parameters should be maintained within applicable emergency limits without system separation or sana: 4.1. Voltage Level: Minimum Maximum © First Power Swing: 0.80 pu V 1.10 pu Vv (for 0.5 sec.) Intermediate: 0.92 pu V 105 pu V (for 2 minutes) Steady State: 0.95 pu V 1.05 pu V 42. Frequency: " 588Hz 61.5 Hz Load-shedding should be planned for adequate system response to multipie contingencies to avoid system collapse. liar of page intentionally blank) 4 ASCC Planning Criteria #2, Page 2 of 2 . 5 ASCC Planning Criteria #4: Support From Adjacent Systems Adequate transmission ties between adjacent systems shall be provided to accommodate planned and emergency power transfers. Requirements Transfer limits for planned emergency power transfers between adjacent systems shall be verified by static, dynamic, and race stability analyses to ensure certian: with all Planning Reliability Criteria, Recommendations 1, Transmission ties should be designed to carry emergency transfers following any single contingency on the interconnected system. Ds Transmission ties should be retained between control areas to the maximum extent practical following a multiple contingency on the interconnected system. . (Remainder of page intentionally blank) ASCC Planning Criteria #4, Page 1 of 1 ‘ 1 ASCC Planning Criteria #5: Reactive Power Resources Each control area shall provide sufficient capacitive and inductive resources at proper levels to maintain system steady state and dynamic voltages within established limits, including support for reasonable levels of planned and emergency power transfers. Requirements ‘1. Devices shall be installed on each system to regulate the transmission voltage and reactive power flow levels, and to keep voltage levels within allowable limits. Devices shall be sized for response to dynamic excursions and to control voltage and power flow in a stable state, once the faulted section has been removed from the system. approved 2, Sizing and location of static Var systems shall be such that any’ single contingency shall not result in the loss of the static Var system. | ae 3. All reactive resource equipment. shall be Liable of continuous operation during system frequency excursions resulting from credible contingencies. 4. Reactive resources shall be sized and provided with controls sufficient to start, operate, and stop them without causing undue adverse system effects. Recommendations 1 Each control area should be able to demonstrate and verify that the equipment has the capability and is responsive to the deficiencies resulting from credible system contingency disturbances, arresting any subsequent system deficiency, and maintaining the system in a stable operating mode. . 2 The size, number, and location of static Var systems, capacitor banks, and reactor banks should be considered in heavily compensated lines which could become unstable due to loss of one static Var system. Reactive resources should be sized and located to minimize the impacts of flicker due to starting, energizing, stopping or de-energizing the devices. ; ; 3, Static Var systems should be designed to Be capable of unconstrained use in the presence of credible harmonics, geomagnetic induced currents and credible frequency swings. 4. Each system should plan and size all reactive supply devices for islanding, in total or in part, from interconnected resources, to control high voltage on open ended lines, and to maintain all voltages and power flows within appropriate limits. 5. Reactive control devices should have the capability of being monitored or controlled through a supervisory control and data acquisition (SCADA) system. ASCC Planning Criteria #5, Pagelofl ~* 8 APPENDIX B N-1 VOLTAGE VIOLATION PTI INTERACTIVE POWER SYSTEM SIMULATOR--PSS/E FRI, JAN 12 1996 10:28 2015 WINTER PEAK, FOR S. TIE STUDY STIE15.SAV "JSES WITH VOLTAGE GREATER THAN 1.0500: X------ BUS <<==- X AREA V(PU) V(KV) X------ BUS ----- X AREA V(PU) V(KV) 212 FT. WAIN12.5 3 1.0538 13.141 986 DAVE SVS12.5 5 1.0996 13.746 998 SOLD SVS9.36 11.0502 9.830 BUSES WITH VOLTAGE LESS THAN 0.9500: X------ BUS ----- X AREA V(PU) V(KV) Xes=s== BUS ----~ X AREA V(PU) -V(KV) 18 SHAW 115 7 0.9495 109.19 19 LAZELLE 115 7 0.9476 108.98 20 LUCAS 115 7: 0.9465 108.85 21 PALMER 115 7 0.9467 108.88 22 DOW 115 7 0.9483 109.06 26 REED 115 7 0.9457 108.75 27 PARKS 115 7 0.9416 108.28 28 PIPPEL 115 7 0.9391 108.00 29 BRIGGS 115 7 0.9398 108.08 31 ONEIL 115 7 0.9471 108.91 40 WORONZOF 138 5 0.9446 130.35 42 INTRNATL34.5 5 0.9213 31.784 43 INTRN 1613.8 5 0.9213 12.714 44 INTRN 2613.8 5 0.9213 12.714 45 INTRN 3G13.8 5 0.9213 12.714 64 PHILLIPS24.9 1 0.8900 22.160 145 JARVIS 138 3 0.9472 130.71 421 INTL-ST134.5 5 0.9213 31.784 422 INTL-ST234.5 5 0.9213 31.784 423 INTL-ST334.5 5 0.9213 31.784 424 INTL-ST434.5 5 0.9213 31.784 599 PLANT2 115 2 0.9430 108.44 604 SUB #12 115 2 0.9387 107.95 605 PLANT1 115 2 0.9290 106.84 611 SUB #10 115 2 0.9299 106.94 613 SUB #14 115 2 0.9313 107.10 614 NLITES T 115 2 0.9302 106.97 615 SUB #15 115 2 0.9301 106.96 616 SUB #8 115 2 0.9279 106.71 617 SUB #16 115 2 0.9257 106.45 618 SUB #7 115 2 0.9256 106.44 619 SUB #6 115° 2 0.9266 106.56 3025 FT GRELY24.9 3 0.9302 23.161 3026 PUMP #9 24.9 3 0.9255 23.045 3027 FT GRELY4.16 3 0.8870 3.690 3200 S-ANCH 138 5 0.9256 127..73 2966 ANCHORGE 115 2 0.9305 107.01 9974 INTRNATB 138 5 0.9276 128.01 9977 UNIVRSTY 230 5 0.8978 206.50 9978 AMLP TAP 230 5 0.9058 208.34 9983 UNIVRSTY 138 5 0.9318 128.59 9984 INTRNATA 138 5 0.9276 128.01 10000 UNIV T3* 5 0.9290 10001 UNIV T3 13.8 5 0.9290 12.820 11000 UNIV T4* 5 0.9290 11001 UNIV T4 13.8 5 0.9290 12.820 PTI INTERACTIVE POWER SYSTEM SIMULATOR--PSS/E TUE, JAN 16 1996 09:33 2015 WINTER PEAK, PARALLEL EXIST. 138KV, FOR S. TIE STUDY EX15138A.SAV 125MW XFER FROM KENAI BUSES WITH VOLTAGE GREATER THAN 1.0500: he ae BUS eae X AREA V(PU) V(KV) BUS ----- X AREA V(PU) V(KV) 212 FT. WAIN12.5 3 1.0538 13.141 986 DAVE SVS12.5 5 1.0938 13.672 998 SOLD SVS9.36 11.0539 9.865 BUSES WITH VOLTAGE LESS THAN 0.9500: X------ BUS ----- X AREA V(PU) V(KV) he BUS ----- X AREA V(PU) V(KV) 38 UNIVRSTY34.5 5 0.9386 32.383 41 WORONZF 138 5 0.9485 130.89 42 INTRNATL34.5 5 0.9425 32.516 43 INTRN 1613.8 5 0.9425 13.006 44 INTRN 2613.8 5 0.9425 13.006 45 INTRN 3G13.8 5 0.9425 13.006 - 64 PHILLIPS24.9 1 0.9019 22.456 -145 JARVIS 138 3 0.9472 130.71 381 UNIV-ST134.5 5 0.9386 32.383 382 UNIV-ST234.5 5 0.9386 32.383 383 UNIV-ST334.5 5 0.9386 32.383 384 UNIV-ST434.5 5 0.9386 32.383 421 INTL-ST134.5 5 0.9425 32.516 422 INTL-ST234.5 5 0.9425 32.516 423 INTL-ST334.5 5 0.9425 32.516 424 INTL-ST434.5 5 0.9425 32.516 3025 FT GRELY24.9 3 0.9302 23.161 +3026 PUMP #9 24.9 3 0.9255 23.045 - 3027 FT GRELY4.16 3 0.8870 3.690 9974 INTRNATB 138 5 0.9472 130.72 9984 INTRNATA 138 5 0.9472 130.72 PTI INTERACTIVE POWER SYSTEM SIMULATOR--PSS/E TUE, JAN 16 1996 09:36 2015 WINTER PEAK, PARALLEL EXIST. 138KV, FOR S. TIE STUDY EX15138A.SAV 125MW XFER FROM KENAI BUSES WITH VOLTAGE GREATER THAN 1.0500: X------ BUS ----- X AREA V(PU) V(KV) a BUS ----- X AREA V(PU) V(KV) 212 FT. WAIN12.5 3 1.0538 13.141 986 DAVE SVS12.5 5 1.0985 13.731 998 SOLD SVS9.36 11.0553 9.878 BUSES. WITH VOLTAGE LESS THAN 0.9500: eee BUS ----- X AREA V(PU) V(KV) Se BUS ----- X AREA V(PU) V(KV) 38 UNIVRSTY34.5 5 0.9325 32.171 42 INTRNATL34.5 5 0.9469 32.669 43 INTRN 1613.8 5 0.9469 13.068 : 44 INTRN 2G13.8 5 0.9469 13.068 45 INTRN 3613.8 5 0.9469 13.068 64 PHILLIPS24.9 1 0.9019 22.456 145 JARVIS 138 3 0.9472 130.71 381 UNIV-ST134.5 5 0.9325 32.171 382 UNIV-ST234.5 5 0.9325 32.171 383 UNIV-ST334.5 5 0.9325 32.171 384 UNIV-ST434.5 5 0.9325 32.171 421 INTL-ST134.5 5 0.9469 32.669 422 INTL-ST234.5 5 0.9469 32.669 423 INTL-ST334.5 5 0.9469 32.669 424 INTL-ST434.5 5 0.9469 32.669 3025 FT GRELY24.9 3 0.9302 23.161 3026 PUMP #9 24.9 3 0.9255 23.045 3027 FT GRELY4.16 3 0.8870 3.690 3200 S-ANCH 138 5 0.9491 130.98 9977 UNIVRSTY 230 5 0.9420 216.67 9978 AMLP TAP 230 5 0.9485 218.16 PTI INTERACTIVE POWER SYSTEM SIMULATOR--PSS/E TUE, JAN 16 1996 11:27 2015 WINTER PEAK, PARALLEL EXISTING LINE SOLDOTNA TO UNIVERS ; EX15230A.SAV 125MW XFER FROM THE KENAI 3USES WITH VOLTAGE GREATER THAN 1.0500: X----== BUS ----- X AREA V(PU) V(KV) X------ BUS ----- X AREA V(PU) V(KV) 212 FT. WAIN12.5 3 1.0538 13.141 998 SOLD SVS9.36 1 1.0785 10.094 BUSES WITH VOLTAGE LESS THAN 0.9500: X------ BUS ----- X AREA V(PU) V(KV) X------ BUS -----! X AREA V(PU) V(KV) 38 UNIVRSTY34.5 5 0.9484 32.719 46 INDIAN 115 5 0.8520 97.984 47 GIRDWODD 115 5 0.8305 95.505 48 PORTAGE 115 5 0.8220 94.531 49 HOPE 115 5 0.8269 95.088 52 LAWING 69.0 6 0.8254 56.952 56 DAVES CR24.9 5 0.8518 21.209 64 PHILLIPS24.9 1 0.8869 22.085 71 BERN Tl 24.9 1 0.9477 23.597 145 JARVIS 138 3 0.9472 130.71 381 UNIV-ST134.5 5 0.9484 32.719 382 UNIV-ST234.5 5 0.9484 32.719 383 UNIV-ST334.5 5 0.9484 32.719 384 UNIV-ST434.5 5 0.9484 32.719 986 DAVE SVS12.5 5 0.9214 11.518 3025 FT GRELY24.9 3 0.9302 23.161 3026 PUMP #9 24.9 3 0.9255 23.045 3027 FT GRELY4.16 3 0.8870 3.690 9985 UNIVRSTY 115 5 0.8959 103.02 9986 DAVES CR 115 5 0.8520 97.978 9987 QORTZ CR 115 5 0.8622 99.154 9991 COOP LK 69.0 5 0.9196 63.450 9993 QRTZ CR 69.0 5 0.9062 62.526 9995 SEWARD 69.0 6 0.7902 54.522 9996 LAWING 115 6 0.8445 97.118 10008 QRTZ T1* 5 0.9062 10009 QRTZ T1T 5 0.9062 PTI INTERACTIVE POWER SYSTEM SIMULATOR--PSS/E SUN, JAN 14 1996 14:45 2015 WINTER PEAK, ENSTAR ROUTE, 230KV, FOR S. TIE STUDY EN15230B.SAV 125MW XFER FROM KENAI SES WITH VOLTAGE GREATER THAN 1.0500: X------ BUS ----- X AREA V(PU) V(KV) X------ BUS ----- X AREA V(PU) V(KV) 212 FT. WAIN12.5 3 1.0538 13.141 986 DAVE SVS12.5 5 1.0870 13.587 BUSES WITH VOLTAGE LESS THAN 0.9500: . X------ BUS te X AREA V(PU) V(KV) X------ BUS ----- X AREA V(PU) V(KV) 64 PHILLIPS24.9 1 0.8769 21.834 71 BERN Tl 24.9 1 0.9384 23.365 72 BERN Tl 4.16 1 0.9487 3.947 73 BERN T1* 1 0.9487 74 KASILOF 115 1 0.9395 108.05 75 ANCH PT 115 1 0.9238 106.23 80 BEAVR CR69.0 1 0.9471 65.348 87 HOMER 24.9 1 0.9389 23.416 145 JARVIS 138 3 0.9472 130.71 3025 FT GRELY24.9 3 0.9302 23.161 3026 PUMP #9 24.9 3 0.9255 23.045 3027 FT GRELY4.16 3 0.8870 3.690 9962 DIAM RG* 1 0.9255 9963 DIAM RGT 1 0.9255 9964 DIAM RDG69.0 1 0.8975 61.927 9965 DIAM RDG 115 1 0.9384 107.92 9992 SOLDOTNA69.0 1 0.9466 65.315 9997 FRITZ CR 115 1 0.9430 108.45 9998 HOMER 69.0 1 0.8891 61.347 10006 SOLD T1* 1 0.9463 10007 SOLD T1T 1 0.9463 APPENDIX C BELUGA ROUTE CORRESPONDENCE OVA MIT 2 DOWER mi ass GINEERS January 15, 1996 Ms. Dora Gropp Manager Transmission and Special Projects Chugach Electric Association, Inc. P.O. Box 196300 Anchorage, Alaska 99519-6300 Subject: POWER Project #120293 Southern Intertie Route Selections Study - Phase 1 Chugach Contract #95208 Kenai-Beluga Submarine Cable Crossing Dear Ms. Gropp: As we discussed Friday, we have completed our initial investigation of a submarine cable crossing from the Kenai, near Birch Hill, to the Beluga side, near Tyonek. Based on our investigations, it is our opinion that a submarine cable crossing of the Cook Inlet at or near these locations, to create a transmission tie line from the Kenai to Beluga, is not feasible. In reaching this conclusion, we have considered both technical and cost factors along with existing cable installation technology and the potential for high maintenance costs and reliability concerns in the future. We will be describing our investigation and conclusions in detail in the Draft Design Section Report. As further explanation, I have attached a memo from Jack Hand, our lead high voltage cable engineer, that briefly describes some ‘of the conditions we have discovered as a result of our investigation. The implication of the rejection of this submarine cable route is that a transmission tie from Anchorage to the Kenai via Beluga across the Cook Inlet is not a feasible alternative. Accordingly, and as you and I discussed, from this point on we will discontinue our work associated with identifying transmission line corridors on the Beluga side of Cook Inlet. In addition, we will modify the study area boundary to exclude the Beluga side of Cook Inlet. We will address the reasons for excluding the Beluga alternative, in detail, in our reports. Please advise if you have any questions regarding this matter or would like to discuss it further. Sincerely, ee : nai Randy Pollock, P Project Manager ab, 120293-01 RM/Ref - Tim Ostermeier RP/ab CHUGACH: So Intertie Route Seiection Study 3 - Randy Pollock Stan Sostrom Ron Beazer : 12 -01 RMW/R y aera / [2V7 Larry Henriksen Frank Rowland Mieki-Gross sermpceicGrew «Jack Hand D&L: Del LaRue PEI-HLY 55-0049 D&M: Garlyn Bergdale-AZ / Tim Tetherow-CO / Niklas Ranta-AK A aA est ta etre RAR anna te) || Westenra | |) lexteemcetes avant ies POWER Engineers, Inc. January 10, 1996 TO: Randy Pollock cc: Tim Ostermeier Ron Beazer 120293-02-22-04-02 FROM: Jack Hand SUBJECT: 120293-02 Cook Inlet Submarine Cable Crossing Tyonek Area to Moose PT/Birch Hill Area After initial investigations, I would like to eliminate the "Beluga" crossing as a practical corridor for the submarine cable portion of the Anchorage-Kenai Intertie. The following are reasons for dismissal of this possible route: The inlet current is swift and changing with the subsurface being swept clean twice a day. According to existing pipeline experience, massive amounts of material moves along the inlet bottom daily and has caused excessive maintenance to the existing pipeline systems. To bury the cable in these waters is not economically feasible, also in a large percentage of the area in the shallow waters a hard exposed rocky bottom will require very expensive excavation, possibly blasting. Moquawkie Indians have authority of ingress to the inlet and feedback indicates this will require significant attention. There is a north/south geological condition approximately 6-7 nautical miles in length and below 10 fathoms where the current typically exceeds 6.5 knots. This area has a hard rock bottom with movement of large boulders back and forth with the tides. This environment is extremely detrimental to cable installation, as well as cable laid on the subsurface. Limited geotechnical reports indicate shifting sands with lava based material in constant motion, this is the area beyond the higher current areas and is a poor choice for submarine cable installation due to’ abrasion. Phillips pipeline has significant annual maintenance to perform to keep their pipeline operational. Their off shore platforms and pipelines have a history of scouring and metal fatigue related failures. PEI-HLY 22-029 Due to the above items the "Beluga" submarine cable crossing will be very expensive. Rough estimates at this time indicate in excess of 150 million dollars under the best scenarios to accomplish the crossing. It would be a poor choice for POWER to recommend such a crossing, both economically and technically. The probability of damage to the cable system during installation is far to great and to require cable burial will make the cost impractical. It’s my opinion that manufacturer/installers would be very wary of this installation and therefore would include substantial contingencies to their bid price. We recommend that the "Beluga" route be eliminated as a possible submarine corridor. Please let me know as soon as possible your decision. cc: Tim Ostermeier 120293-02 RM/Ref N PEI-HLY 22-029 APPENDIX D PUBLISHED PAPERS REGARDING TCSC AND BES SYSTEMS SUBSYNCHRONOUS RESONANCE PERFORMANCE TESTS OF THE SLATT THYRISTOR-CONTROLLED SERIES CAPACITOR RJ. Piwko (SM), C.A. Wegner (M) GE Power Systems Engineering Schenectady, NY 12345 Abstract — A thyristor-controlled series capacitor (TCSC) has been designed, installed, and field tested on the BPA 500 kV transmission system. The Slatt TCSC is a variable series capacitor with high control bandwidth. Field test results demonstrate that this TCSC does not participate in or contribute to subsynchronous resonance (SSR). It is SSR neutral in itself, and it can reduce SSR effects due to other nearby conventional series capacitors. Keywords — Series capacitor, thyristor, subsynchronous resonance, SSR, 1. INTRODUCTION AND BACKGROUND A thyristor-controlled series capacitor (TCSC) has been installed at the C.J. Slatt 500 kV substation in northern Oregon, USA. Project participants included GE, BPA, EPRI, and Portland General Electric. Several previous papers describe the overall project [1,2]. This paper focuses exclusively on the performance of the TCSC with respect to subsynchronous resonance (SSR). The Slatt TCSC is comprised of six identical thyristor- controlled capacitor modules connected in series. Each module is nominally 1.33 ohms capacitive, with transient overload capability of 4 ohms. The TCSC has a continuous line current rating of 2900A, with 30 minute and 10 second overload capabilities of 4350A and 5800A. A one-line diagram is shown in Figure 1. The ability.of a TCSC to avoid subsynchronous Teson. is one of its most important performance attributes. Much design and testing work during this project has focused on demonstrating SSR mitigation. In fact, the Slatt site was chosen because it offered the best opportunities for such testing, when compared to the numerous other sites considered for this project. Portland General Electric generously contributed the use of its Boardman turbine-generator, as well as numerous hours of planning and test support, and made this test possible. Those contributions are gratefully acknowledged by the rest of the project team. 2. SSR CONCEPTS AND THE INFLUENCE OF TCSC ance As an example of how the TCSC responds to subsynchronous oscillations on a transmission line, consider the simple system shown at the top of Figure 2. This 95 SM 402-8 PWRD A paper recommended and approved by the IEEE Transmission and Distribution Committee of the IEEE Power Engineering Society for presentat- ion at the 1995 IEEE/PES Summer Meeting, July 23-27, 1995, Portland, OR. Manuscript submitted January 3, 1995; made available for printing May 3, 1995. His S.J. Kinney (M) J.D. Eden (M) Bonneville Power Administration Portland General Electric Portland, OR Portland, OR To Buckley Bypass To Slatt < Disconnect > Pee ULE |solation Series Capacitor Mi Varistor Isolation TCSC Module, l Reactor bs ‘ga Thyristor Reactor Valve ce Bypass Breaker Fig. 1. One-line diagram of Slatt TCSC. system consists of two infinite buses connected by an inductor anda capacitor representing a series compensated transmission line. If this system is stimulated by a minor disturbance, it oscillates at its natural frequency of 15 Hz as shown on the left side of the figure. The traces of line current and capacitor voltage are 60 Hz, modulated by the large 15 Hz subsynchronous oscillations. If the series capacitor in the line is replaced by an equivalent TCSC operating in the vernier mode, the response to the same >] Thyristor Current Disturbance a 1! ; Capacitor Voltage a Capacitor Voltage Line Current iH Line Current CR Sheep eh ee ee o O41 02 o O41 02 (Seconds) (Seconds) (a) Conventional Series Capacitor (b) TCSC With Vernier Firing Control Fig. 2. Example of TCSC damping subsynchronous electrical oscillations. torsional oscillations. This included the following specific goals: 1. To compare the SSR performance of the TCSC with that of conventional series capacitors under the same set of system operating conditions. 2. To quantify the effect of the TCSC’s vernier firing control system on the damping of machine torsional oscillations. To evaluate the ability of a small TCSC to mitigate and/or reduce the SSR caused by a conventional series capacitor. All SSR tests were performed with the Boardman machine operating in a “radial” system condition, as illustrated in Figure 4. By opening other transmission lines emanating from Slatt, the machine was isolated on a single radial transmission line connecting Boardman to Buckley through Slatt and the TCSC. Different operating conditions were created by placing the six TCSC modules in different combinations of operating conditions (including bypassed, inserted as conventional capacitors, and inserted with normal thyristor control). All measurements of torsional damping were obtained by stimulating the machines torsional modes of oscillation one at a time and recording the decay after the stimulus was removed. The TCSC itself was used to stimulate the oscillations by modulating the TCSC reactance order with an oscillator set to the torsional frequency. A total of 96 such tests were performed during a two-day testing session. Definition of Terms Breaker-Bypass — The TCSC bypass breaker is closed, so the entire six-module TCSC is bypassed (short- circuited). - Thyristor-Bypass - A given module is bypassed by continuous gating of the thyristor switch. Essentially all line current flows through the thyristor switch. Blocked A given module is inserted as a “conventiol series capacitor by completely stopping (blocking) gating of the thyristor switch. All line current flows through the capacitor. Vernier — A given module is inserted and the thyristor switch utilizes phase-controlled gating to circulate some current through the switch and the capacitor. This is how a TCSC normally operates. 4, KEY FIELD TEST RESULTS The key aspects of the test results can be illustrated by examining a few representative tests. They focus on Mode 4, since that is the only mode that can be destabilized by SSR at Slatt. Figure 6 contains test results for the base system with no series compensation. The plot shows Mode 4 speed deviation versus time. The mode was initially stimulated using an oscillator to vary the ohms order of the TCSC at 50 Hz. The constant level of stimulation can be seen for the first 5 seconds of the response. At 5 seconds, the stimulus was removed and the TCSC bypass breaker was closed, effectively removing the entire TCSC from the circuit. The torsional oscillation decays within the next 10 seconds. Damping can be quantified as o, the real part of the eigenvalue, with units of inverse seconds (1/second). Boardman Slatt Buckley = ° Speed Deviation in % o £ ° 10 15 Time in Seconds Fig. 6. Response of Mode 4 to closing the TCSC bypass breaker; no series compensation. Boardman radial to Buckley. 20 25 30 For this case, o is 0.36. This serves as a benchmark for other cases, since it represents the damping with no series compensation in the system. Figure 7 shows the response of Mode 4 when five TCSC modules are inserted as conventional series capacitors (i.e., with the thyristor gating blocked). The 6th module is bypassed. The plot shows the initial stimulus for the first 5 seconds, after which the 5 capacitors modules are inserted by blocking thyristor gating. A transient occurs initially due to the capacitor insertion. Within 5 seconds the transient has decayed and the torsional response remains constant at a value slightly below the initial level. The Mode 4 torsional oscillation does not decay, indicating that for this case the damping, 6, is zero. This is a severe SSR condition. Figure 8 shows the same case, but this time the five TCSC modules are inserted with normal vernier control. The torsional decay response indicates that Mode 4 is very well damped (o = 0.35). In fact, torsional damping with the TCSC is the same as with no series compensation at all. Figure 9 addresses a test condition to evaluate the effectiveness of a small TCSC in reducing SSR caused by a separate conventional series capacitor. For this test, the initial stimulus was again the same as previous tests. At 5 seconds, 5 modules were placed in blocked operation and one module was placed in vernier operation. The transient due to that event is evident, and then the torsional oscillation decays with o = 0.13. Comparing this result with that in Figure 7 shows that adding the one module with vernier control improved torsional damping from 0 to 0.13, and has changed the operating condition from one Boardman Slatt ce z l l 5 Modules a Test 18 2° o Speed Deviation in % é £ 10 15 Time in Seconds Fig. 7. Response of Mode 4 to inserting five modules with thyristor gating blocked. 6.67 ohms of “conventional” series compensation. 20 25 30 -3e 2. Set the oscillator’s frequency to the mode being stimulated and gradually increase the magnitude until the shaft response reaches the desired level. Allow the oscillations to stabilize at a constant steady-state level. Remove the modulation signal and simultaneously reconfigure the TCSC to the operating condition desired for the damping measurement. Record the decay of the torsional oscillations and calculate the damping. 6. COMPLETE TEST RESULTS Baseline Damping, All Lines In, No Series Compensation Test Series 1 examines the level of torsional damping in all four modes with all transmission lines in service and with no series compensation in the transmission network near Boardman. The results are shown in Table 1. These values represent a baseline of comparison for other operating conditions with series compensation and/or the TCSC. TABLE 1 RESULTS OF TEST SERIES 1 ALL LINES IN; NO SERIES COMPENSATION Mode 1 Mode 2 Mode 3 Mode 4 Damping Damping Damping Damping 11.92 Hz 23.32 Hz 27.32 Hz 49.95 Hz Us Us) ‘Us Us) 0.311 0.178 0.138 0.371 SSR with Conventional Series Compensation Test Series 3 varied the amount of series capacitance in the line from zero to 8 ohms by inserting different numbers of TCSC modules with thyristor gating blocked. The results are shown in Table 2 and Figure 11. Torsional damping measurements for Modes 2 and 4 were made for all levels of compensation. Damping for Modes 1 and 3 were only measured at a few compensation levels, since no significant damping changes were expected. The test results show that the damping of Modes 1, 2, and 3 are relatively unaffected by the number of series capacitor modules inserted. Mode 4, however, experiences a subsynchronous resonance condition when five capacitor modules are inserted. This is a classic case of subsynchronous resonance, where the natural resonant frequency of the electrical system interacts with a machine torsional oscillation to dramatically reduce its damping. In TABLE 2 RESULTS OF TEST SERIES 3 VARIED AMOUNT OF CONVENTIONAL SERIES COMPENSATION Number Number Model Mode 2 Mode 3 Mode 4 of of Damping Damping Damping Damping Modules Modules 11.92Hz 2332Hz 2732Hz 49.95 Hz Blocked _Bypassed __(1/s) (14) (Us) (Us) 0 6 0.265 0.165 0.138 0.357 1 5 0.159 0.368 2 4 0.163 0.305 3 3 0.260 0:161 0.132 0.322 4 2 0.150 0.259 Ss 1 0.150 0 6 0 0.239 0.159 0.136 0.280 2 3 4 6 Number of Modules Blocked Fig. 11. Results of Test Series 3; varied amount of conventional series compensation by blocking thyristor gating on selected modules. ° 1 this case, the damping of Mode 4 is reduced to zero with five capacitor modules inserted. This operating condition serves as the “worst-case SSR” test condition for evaluating the SSR performance of the TCSC. In fact, the existence of this Mode 4 SSR condition is one of the primary reasons why the Slatt substation was selected for this project. Results of subsequent tests show that the TCSC’s vernier firing control eliminates the negative damping effects of this SSR condition. SSR With TCSC Compensation Test Series 5 is essentially the same as Test Series 3, except that the inserted TCSC modules were operated with their normal vernier firing control. That is, the same levels of series compensation were placed in the Slatt-Buckley line, but the compensation was TCSC rather than conventional series capacitors. The amount of compensation was varied from zero to six modules. The results are presented in Table 3 and Figure 12. The test results dramatically show that the TCSC with vernier control totally eliminates the subsynchronous - resonance condition that was evident with the conventional series capacitors in Test Series 3. Damping for all four torsional modes is relatively constant over the range of modules inserted. The damping of Modes 1, 2, and 3 are essentially the same as in Test Series 3. The resonance TABLE 3 RESULTS OF TEST SERIES 5 VARIED AMOUNT OF TCSC COMPENSATION Number Number Model Mode 2 Mode 3 Mode 4 of of Damping Damping Damping Damping Modules Modules 11.92Hz 2332Hz 2732Hz 49.95 Hz in Vernier _Bypassed (Us) (Us) (Us) (Us) 0 6 0.265 0.165 0.138 0.357 1 s 0.311 2 4 0.282 3 3 0.242 0.167 0.132 0.368 4 2 0.351 5 1 0.351 6 0 0.224 0.165 0.132 0.337 TABLE 5 RESULTS OF TEST SERIES 7 SMALL TCSC WITH LARGER CONVENTIONAL SERIES CAPACITOR (5 MODULES BLOCKED, ONE IN VERNIER) Mode 4 Damping 49.95 Hz 1d 0.128 12 0.104 15 0.086 2.0 0.061 3.0 0.046 0.14 0.12 Mode 4 0.04 0.02 ° — — i | 1 1.5 2 25 3 TCSC Vemier Order, Xorg (Pu) Fig. 15. Results of Test Series 7 showing effect of a small TCSC with a larger conventional series capacitor. that the TCSC installed at the Slatt substation has achieved that challenging goal. The early stages of the development program included extensive digital computer simulations of SSR interactions, both in the time domain and in the frequency domain. The control designs were then implemented in prototype digital control hardware and tested on a TNA for SSR performance. The field tests were the final actual-system confirmation that the TCSC does not introduce SSR to the host system. The results of the SSR field test program have demonstrated the following: 1. The TCSC is “SSR-neutral”. For a machine connected to a transmission line with TCSC compensation, torsional damping is the same as if there was no series compensation whatsoever. A TCSC can mitigate SSR due to other series capacitors. A TCSC installed in a line that already has conventional series capacitors can significantly reduce the detrimental SSR effects of the series capacitors. The field test results were essentially identical to the simulation results obtained using digital programs and TNA measurements. This verifies that the simulation tools can confidently be used to analyze and predict SSR performance for future TCSC installations. It also establishes these simulation tools as a means of pursuing further SSR control developments. REFERENCES (1) J. Urbanek, R.J. Piwko, E.V. Larsen, B.-L. Damsky, B.C. Furumasu, W. Mittlestadt, J.D. Edan, “Thyristor Controlled Series Compensation Prototype Installation at the Slatt 500 kV Substation,” JEEE Transactions of Power Delivery, July 1993, pp. 1460-1469. R.J. Piwko, C.A. Wegner, B.C. Furumasu, J.D. Eden, B.L. Damsky, “The Slatt Thyristor Controlled Series Capacitor Project Design Installation, Commissioning, and System Testing,” CIGRE Paper 14-104, Paris, August 1994. A.T. Hill, E.V. Larsen, E. Hyman, “Thyristor Control for SSR Suppression, A Case Study,” EPRI FACTS-3 Conference, Baltimore, October 1994. [2] (3] BIOGRAPHIES Richard J. Piwko (S'74, M'744, SM’85) a native of Massachusetts, received the BSEE and MSEE degrees from Worcester Polytechnic Institute. He joined GE in Schenectady, New York, in 1976, and is presently a Consulting Engineer in the Power Systems Engineering Department. He is involved in design and performance analysis of turbines, generators, HVDC systems, static var systems, and thyristor controlled series capacitors, as well as the analysis and mitigation of torsional interactions among such power system devices. Mr. Piwko is active on several IEEE working groups, subcommittees and committees in the HVDC, FACTS, and system dynamic performance areas. He has authored more than fifty technical papers dealing with power system dynamics and control. Carl Wegner obtained the BSEE with university honors from University of Illinois in 1982, and the MSEE from Illinois in 1983. He then joined GE, and developed microprocessor based reactive controls for Miles City and New England HVDC projects. He worked for A.B. Chance and CGEE Alsthom from 1987 to 1989. He rejoined GE in 1989 with Power Systems Engineering Department. His work involves control related studies and equipment implementation. He led the contro! implementation for the EPRI TCSC project. Mr. Wegner has co-authored several technical papers. Scott J. Kinney (S'88, M’91) was born in Spokane, Washington in 1968. He received his BS degree magna cum laude in Electrical Engineering from Gonzaga University in 1991. Mr. Kinney joined the Bonneville Power Administration in 1991, and is presently the BPA project manager for the Slatt TCSC demonstration project. He is responsible for the coordination of the testing and commercial operation of the TCSC prototype. Mr. Kinney is active in the IEEE capacitor subcommittee and is a member of several capacitor working groups and task forces. He has co-authored several papers describing the results of Slatt TCSC performance James D. Eden (M’81) was born in 1954 in Louisiana. He received his BS degree magna cum laude in Electrical Engineering from Oregon State University in 1979. Mr. Eden joined Portland General Electric Company (PGE) in 1979 and is presently in the position of Principal Planning Engineer. He has been responsible for developing long-range transmission plans, integrating generation projects, regional planning and has extensive experience in dynamic analysis and control systems. For the past seven years he was responsible for the planning and development of the expanded Pacific AC Intertie system for PGE. Mr. Eden is also currently serving as industry advisor to this TCSC project. Mr. Eden is a registered Professional Engineer in the state of Oregon and is also a member of IEEE, NSPE, Eta Kappa Nu and Tau Beta Pi. Te a Series Capacitor High-Speed Power re al | en ren September 1993 he world’s first multi-module thyristor-controlled series capacitor (TCSC) system has been installed on Bonneville Power Administration’s transmission sys- tem. The TCSC is part of EPRI’s Flexible AC Transmission System FACTS program, and was funded by EPRI, BPA and GE. Portland General Electric is funding por- tions of the test program. This installation is located at BPA’s C_J.Slatt substation on the Slatt-Buckley 500 kV line in Northern Oregon. At the substa- tion, six identical thyristor con- trolled capacitor modules are sapplied to each of the three phases. The capacitors, current limiting reactors, thyristor switcti- es and protective varistors are located on three platforms, which are at the potential of the 500 kV line and insulated fora BIL of 1550 kV. In addition, each phase has line disconnects and a bypass breaker. The advanced digital control and protection system, located in a building at ground potential, consists of a master controller and a con- troller for each capacitor mod- ule. Communication between platform and ground is accom- aeons by fiber optics. The are liquid-cooled via a ground- -based heat exchanger. - water-glycol mixture is used for this outdoor application. Performance Benefits > high speed switch- ing capability provides a mecha- nism for controlling line power flow, which permits increased Figure 1. Aerial views of TCSC at C. J. Slatt substation. Control Center Hanford Slatt Substation Figure 2. The Pacific Northwest 500 kV transmission system. lines, and allows for rapid read- justment of line power flow in response to various contingen- cies. The TCSC also can regulate steady-state power flow within its rating limits. Transmission loading may be limited by system stability or tran- sient stability of generation. The TCSC is a powerful new tool to help relieve these constraints. Its controls can be designed to mod- ulate the line reactance and pro- vide damping to system swing modes, with dramatic results. This condition was simulated | using the actual Slatt control sys- tem and GE’s power system simu- lator with damping deliberately reduced. (See Figure 3.) In the top trace, large, undamped sys- tem swings are produced as the result of a fault. At six seconds the TCSC damping function is manually engaged, at which point there is a dramatic increase in the damping. The control deadband stops further action in this test case, but nor- mally the system’s inherent damping would make the power swings die out entirely. The level of damping introduced by the TCSC, per dollar invested, is unequaled by any other device and the fast action permits increased line loading for the same stability constraint. The output of generating plants may also be limited by transient instability under cer- tain contingency conditions. The fast-acting TCSC can pro- vide the means of rapidly increasing power transfer upon detection of the critical contin- gencies, resulting in increased transient stability. Finally, the TCSC provides a mechanism for greatly reduc- ing a potential subsynchronous resonance problem at thermal generators electrically close to transmission lines with series compensation. In some cases, the inability to mitigate SSR with conventional series capaci- tors has limited line compensa- tion to levels between 20 and 40 percent. With even a small percentage of TCSC, the total compensation can be increased significantly. 2 4 6 TCSC Damping 10 12 14 16 18 20 f Time (Sec.) Control Engaged Figure 3. Damping benefits of TCSC simulated at GE using actual controls. Isolation Disconnect Series Capacitor 7 Varistor Valve Bypass Breaker To Slatt K, Isolation Disconnect (with Resistor) Figure 4. One-line diagram of Slatt TCSC. Overview of Slatt TCSC Figure 4 shows an elementary one-line diagram of the Slatt TCSC. It is comprised of six iden- tical TCSC modules connected in series. Each module consists of a capacitor, a bi-directional thyristor valve (with its associated reactor), and a varistor. A bypass breaker (with its associated reac- tor) is connected. across the entire device for use in opera- tional and protective functions. Also, three disconnect switches are used to bypass and isolate the TCSC from the Slatt-Buckley transmission line. Basic Operating Principles Each module can operate either bypassed or inserted. In addition, when the capacitor is inserted, the thyristor valve can be phase-controlled to vary the effective fundamental-frequency impedance of the capacitor. The basic operating principles are explained below. While bypassed, the thyristors are gated for full conduction, and the net reactance of the module is slightly inductive because of the reactor in series with the thyristor valve. This is illustrated in Figure 5a. Note that b) Inserted with no thyristor valve current (gating blocked). —_—_—_—_—_— oD C) Inserted with vernier control, circulating some current through thyristor valve. Figure 5. TCSC control modes. some current also flows through the capacitor during bypassed operation, but most flows through the thyristor valve and reactor because it isa much lower impedance path. If the capacitor is inserted by turning off the thyristor valve (that is, blocking all gating sig- nals to the thyristors), the effec- tive capacitance of the module is the same as its nominal value. This is illustrated in Figure 5b. This mode of operation is essen- tially the same as for a conven- tional series capacitor. While the capacitor is insert- ed, the thyristors can be gated near the end of each half cycle in a manner that can circulate a controlled amount of inductive current through the capacitor, thereby increasing the effective capacitive reactance of the mod- ule. This concept, referred to as vernier control, is illustrated in Figure 5c. In this mode, the inserted reactance can be con- trolled in a continuously-variable (vernier) manner from a mini- mum value of the capacitor alone (1.33 ohms) to as much as 4.0 ohms. The upper limit for vernier operation is a function of line current magnitude and time spent at the operating point. The Slatt TCSC consists of six modules. The operation of all six modules is automatically coordi- nated from a higher level control system called the common con- trol. All modules receive “ohms” orders from the common level, and these orders establish the operating mode and vernier level for each individual module. Operating Capabilities of Slatt TCSC Each individual module can either be bypassed or inserted with vernier control. With the module bypassed (thyristor valve continuously gated), the module Slatt TCSC Ratings (Six Modules) Nominal System Voltage (Line-to-Line) Nominal Capacitive Reactance Nominal Three-Phase Compensation Continuous Effective Capacitive Reactance Maximum Effective Capacitive Reactance Net Inductive Reactance (All Modules Bypassed) Rated Line Current 30-Minute Overload Current 10-Second Overload Current Maximum 3 6 RMS Fault Current Through TCSC Maximum Crest Fault Current in Thyristor Valve has a net impedance of 0.2 ohms inductive. (The net imped- ance when bypassed is the paral- lel combination of the capacitor and the reactor.) With the mod- ule inserted, its capacitive reac- tance is between 1.33 ohmis and 4.0 ohms. The actual level of effective ohms is determined by the magnitude of current circu- lated through the thyristor valve in the vernier control mode. The operating capability for the entire six-module TCSC is shown in Figure 6. Given that the control system can operate the modules in any combination of bypassed or vernier modes, the TCSC can vary its total effective impedance anywhere within the shaded region of the plot. Short- term overload operation is possi- ble at higher levels of line cur- rent and/or effective ohms. Sep- arate regions are shown for 30- minute and 10-second overload capabilities. Nominal rating of the Slatt TCSC bank is 8 ohms at 2900 Amps, which is equivalent to 202 MVA~r. To provide a bias for mod- ulation control and to imple- ment the modified NGH SSR damping feature, the reactance can be increased by vernier con- trol to 1.53 ohms/module (9.2 ohms for all six modules) in steady-state at nominal current. The limit on vernier control is a 500 kV 8.00 Ohms 202 Mvar 9.20 Ohms 24 Ohms 1.22 Ohms 2,900 A 4,350 A 5,800 A 20.3 kA 60 kA function of line current and duration. A 10-second limit of 16 ohms applies at nominal current, with 12 ohms being allowed for 30 minutes. The temporary over- load impedance varies with line current and is consistent with IEEE Standard 824 for series capacitors, considering both dielectric stress and total rms current through the capacitors. The basic ratings of the Slatt TCSC are summarized in the above table. Rating and Specification Issues When specifying a TCSC, the added dimension of thyristor control increases the number of factors to be considered, as com- pared to conventional series compensation. The cost of a TCSC is driven primarily by the maximum voltage it must create in series with the line and by the maximum line current. Voltage rating must be established based on steady-state and transient per- formance requirements. Here are some of the most important considerations: Maximum Overvoltage - The - protection level and energy requirements are the primary design considerations for the voltage-limiting metal oxide varistor. The protective level is dictated by the short-time over- voltage requirement of the TCSC. The varistor energy capa- bility is determined by external faults, where the TCSC must be kept in service during the fault. Transient studies can be per- formed to determine the varistor energy requirements, which are significantly less than those for a conventional bank with a compa- rable rating. Thyristor Valves - These are a major component of the TCSC. Ratings are determined by the protective voltage level and by continued... 30 20 Continuous Effective Ohms of Entire TCSC (+ is Capacitive) 3 0 1000 2000 Ae 30 min. Overload Region 10 sec. Overload Region All Modules Bypassed (-1.2 Q Inductive) 3000 4000 5000 6000 Line Current (amps rms) Figure 6. Capability curves for the Slatt 6-module TCSC. 7. The Slatt TCSC control system. Figure multiple microprocessors. Figure 8. Digital controls with om Figure 9. Phase A platform of the Slatt TCSC. the fault current requirements, as well as the maximum thyristor current that must be continuous- ly sustained. Capacitors - To achieve system performance benefits with a TCSC, the capacitor rating must be slightly different than that required for a conventional bank, since harmonic currents are imposed by vernier operation. Harmonics in the line current are not expected to be a signifi- cant issue with TCSC applica- tions, especially if multi-module For Further Information systems are used. This is because nearly all of the harmonic cur- rent is contained within the capacitor-reactor-thyristor loop. However, the system should be studied to determine harmonic constraints. : TCSC can be an overall system solution for utilities needing to operate their transmission sys- tems at higher power transfer levels. An evaluation can be read- ily performed to determine the potential system benefits and the economic implications. Please contact Mr. Richard Piwko at GE on (518) 385-7610. Further technical information is contained in the following references. “Characteristics and Rating Considerations of Thyristor Controlled Series Compensation,” by E.V. Larsen, K. Clark, S.A. Miske, Jr. and J. Urbanek, presented at the IEEE 1993 Summer Power Meeting. “Thyristor-Controlled Series Compensation — Prototype Installation at the Slatt 500 kV Substation,” by RJ. Piwko, J. Urbanek, E.V. Larsen, B.L. Damsky, B.C. Furumasu, W.A. Mittelstadt, J.D. Eden, presented at the IEEE 1992 Summer Power Meeting. “Effectiveness of Thyristor Controlled Series Capacitor in Enhancing Power System Dynamics: An Analog Simulator Study,” by S. Nyati, C. A. Wegner, R.W. Delmerico, R.J. Piwko, D.H. Baker, A. Edris, present- ed at the IEEE 1993 Summer Power Meeting. “Benefits of Thyristor-Controlled Series Compensation,” by E.V. Larsen, C.EJ. Bowler, B.L. Damsky, S.L. Nilsson, CIGRE SC 14, Paris 1992. @ GE Industrial & Power Systems Power Systems Engineering One River Road, Schenectady, NY 12345 GEA12240 SYNCHRONOUS VOLTAGE REVERSAL (SVR) SCHEME - A NEW CONTROL METHOD FOR THYRISTOR CONTROLLED SERIES CAPACITORS L. Angquist H. Othman G. Ingestr6m Transmission Technology Institute Reactive Power Compensation Division ABB Power T&D Inc ABB Power Systems AB 1021 Main Campus Drive S-721 64 Vasteras, Sweden Raleigh, North Carolina 27606-5202 Abstract A new control method for Thyristor Controlled Series Capacitors (TCSC) is presented. It is shown in the paper that the operation of the TCSC can be described in terms of equivalent instantaneous voltage reversals. This approach forms a convenient base for synthesis of a control system that governs the voltage boost of the TCSC and simultaneously makes the TCSC exhibit a virtual impedance in the subsynchronous frequency range that eliminates the risk of SSR. The paper describes the ideas behind . the concept and outlines the control system. 1. Characteristics of TCSC The TCSC concept, outlined in figure 1, has been around for some years and has attracted a lot of interest. Figure 1. Outline of TCSC In principal it realises a controlled voltage source that is inserted in series with the transmission line. Due to this configuration in the transmission system the device exhibits beneficial performance in power flow and damping control applications (1),(2),(3): high efficiency; favourable quotient MW change / inserted Mvar equipment location along the line can be freely selected damping performance is insensitive to terminal loads and their voltage characteristics damping of inter-area oscillations always contributes positively to damping of local power oscillation modes Theoretical investigations of TCSC performance in the past addressed subjects like fundamental voltage control and harmonic voltage generation. Steady-state formulas for the virtual reactance of the TCSC can easily be deduced and have been published e.g. in (4). The characteristics most often have been presented with the trigger angle as a parameter. The trigger angle a is defined as the angular delay from the earliest instant when the thyristor blocking voltage becomes positive to thyristor turn-on. The resulting characteristics of the TCSC virtual reactance at fundamental frequency typically looks like figure 2. The curves are strongly non-linear and exhibits at least one asymptote. The parameter A indicates the ratio between the resonance frequency of the LC circuit constituted by the series capacitor together with the inductor in the thyristor branch and the rated frequency of the mains. TCSC Virtual reactance inductive m/(2A) Figure 2 Typical steady-state characteristics of TCSC Most implementations of control systems for TCSC operate with the trigger angle a as an interfacing quantity between the control system and the main circuit. A typical approach is shown in figure 3. The Phase-Locked Loop (PLL) synchronises thyristor triggering to actual AC quantities in the transmission system. Dynamical studies (5) show that the stability of the circuit is improved by locking the PLL to line current ( 'i_ synchr' in figure 3) as compared to the case when it is locked to capacitor voltage (‘uc synchr' in figure 3). Figure 3 Conventional TCSC control system Recent investigations of TCSC performance address its virtual impedance characteristics in the subsynchronous frequency range (6). It has been shown that TCSC exhibits a virtual impedance that deviates substantially from that of a fixed capacitor. Consequentially its SSR behaviour also is different. In the following sections of this paper a new approach to describe the TCSC action will be introduced. A related contro! method, named Synchronous Voltage Reversals (SVR), exhibits interesting performance with respect to stability and virtual impedance. In principle an unrestricted degree of series compensation may be used without fear for SSR. 2. Physical description of TCSC action The natural objective of the inner TCSC control, as for any device that involves a large capacitor bank, is to keep the voltage under control. More specifically, a reasonable target is to control the “boost voltage", i.e. the voltage created by the charges (current pulses) that circulate through the thyristors in the TCSC main circuit. This circulating charge adds to the charge provided by the line current. The correlation between the charge which passes through a thyristor when it is turned on and the corresponding trigger angle is not easily defined dynamically. The relation involves dynamics of the TCSC main circuit and the transmission line. A much closer connection exists between the capacitor voltage at thyristor tum-on (Uc) and the charge. Actually, if the circuit inductance is small or if the initial capacitor voltage is high, this initial voltage, Uco, exclusively determines the charge that passes through the thyristor. Whenever a thyristor is triggered the capacitor voltage reverses its polarity and the charge Qy = 2C Uco passes through the thyristor branch. The above approximation is valid as long as the charge Qj dominates over the charge Q,_ =] i, dt which is provided by the line current during the thyristor conduction time. thyr cond As long as this condition is valid (QT >> Q,) the thyristor conduction time constantly equals half the period time that corresponds to the resonance frequency of the TCSC main circuit (A fy). When Q, contributes significantly to the total capacitor charge the duration of the thyristor conduction interval becomes shorter. Yet, under a wide range of conditions, the transient in the circuit caused by thyristor turn-on can still be characterised as a capacitor voltage reversal (although with varying reversal time). REAL SYSTEM Uo a) b) Figure 4 Capacitor voltage reversal a) capacitor voltage (upper), line current and thyristor current (lower) b) modelling using instantaneous voltage reversal approximation In figure 4a the line current is approximated as being constant during the thyristor conduction time; this approximation is motivated by the fact that the thyristor conduction intervals appear in the proximity of the line current absolute maxima where the current variation is slow. Figure 4b shows that the boost voltage that is created during the finite time reversal is identical to that which would be obtained at an instantaneous voltage reversal in the midpoint of the thyristor conduction interval. The influence of the TCSC thyristor control on the transmission system almost entirely is associated with the amount of additional voltage Aug across the capacitor. Thus, from the transmission system point of view, nearly identical performance would be obtained if the TCSC accomplished equivalent instantaneous voltage reversals in the middle of the thyristor conduction interval as indicated in figure 4b. The delay between thyristor turn- on and the instant of each equivalent voltage reversal obviously depends on the duration of the conduction interval, which in its turn is a function of the line current in the interval and the capacitor voltage at thyristor turn-on. The following sections present a description of the TCSC based on this instantaneous voltage reversal concept. It is shown that the capability of accomplishing controllable voltage reversals can be regarded as the main mechanism of interaction between the TCSC and the transmission system. 3. TCSC impedance response at subsynchronous frequencies The virtual impedance of the TCSC expresses its linearized voltage response to small superimposed line current deviations when operating in steady-state with constant line current at rated frequency wy. Assume that the superimposed current is sinusoidal, has much smaller amplitude than the steady-state current and has the angular frequency Q. The virtual impedance then is defined as the quotient between the phasor that represents the capacitor voltage component with frequency Q and the phasor with same frequency that represents the superimposed current. The additional capacitor voltage caused by the superimposed line current is proportional to the corresponding charge i.e. to the integral of the additional line current. The capacitor voltage reverses with the repetition frequency 2*fyj=on/z due to the action of the TCSC for the fundamental frequency line current. The combined effect of integration and voltage reversals determines the voltage response of the TCSC. At very low frequency the impedance tends to vanish (in contrast to the conditions in a fixed series capacitor) as the charge accumulation in the TCSC capacitor is prevented by the capacitor voltage reversals that occur with the given repetition frequency. If we assume that the conduction interval midpoints are unaffected by the superimposed line current and remain at their steady-state positions and if we further approximate the voltage reversals having finite duration with instantaneous ones, then the voltage response can be calculated. Interpreting the system as a discrete, sampled system with sampling frequency fs=2*fy an analytical expression for the virtual impedance can easily be obtained. In a further refined analysis a loss factor D is introduced to represent the circuit losses. The capacitor voltage after reversal (notation as in figure 4) then is given by uc(ty) = -D*uc(0)= -D"uco where 0<Ds1 Figure 5 presents the results of calculations using such a model of the TCSC. It shows a very interesting result: the virtual impedance is resistive-inductive in the whole subsynchronous frequency range. The result remains valid independent of any tr issit m T in circui fe Vv boost level, Virtual li | "vir!*Crated vit Crated 9 u .——+t ° cr) 1 (Hz) 1 (Hz) Figure 5 Virtual reactance of TCSC (fjj=60 Hz) Again, the above result was obtained assuming instantaneous voltage reversals at fixed time instants, which are defined by the steady-state line current and which are unaffected by the superimposed current. Figure 6 illustrates the additional voltage caused by a 25 Hz superimposed current in,a 60 Hz system. Figure 6 Additional capacitor voltage for 25 Hz superimposed current (fy=60 Hz) superimposed current:=1 pu, rated capacitor reactance 1 pu The dashed line is the additional 25 Hz line current and the black solid curve shows the instantaneous additional capacitor voltage. The integration of the superimposed current is recognised by the curve segments with finite derivative and the voltage reversals show up as vertical line segments. In the sampled-data model the capacitor voltage is sampled in the midpoint of the intervals between the voltage reversals. The sampling points are marked by circles. The gray solid curve represents the 25 Hz component of the voltage. By comparing the voltage and current curves it can be concluded that this voltage represents an inductive reactance. So far instantaneous voltage reversals have been discussed. Figure 7 reveals the changes that occur if the TCSC equivalent voltage reversal instants are fixed, but the duration of the voltage reversal process is finite. thyristor Figure 7 Impact of finite reversal time on additional capacitor voltage It can be seen that the duration of the thyristor conduction intervals has a minor impact on the average value of voltage between the sampling points. Ideally the voltages in the sampling points are not influenced at all. Accordingly the virtual impedance which was derived for instantaneous voltage reversals will remain almost unchanged when the thyristor conduction time has finite duration if thyristor triggering is modified so that the ‘capacitor voltage zero-crossing instants (=peak current instants) are preserved in their steady-state positions. : 4. Average boost level control The instantaneous voltage reversal concept, as illustrated in figure 4b, also is a very handy representation to describe the interaction between the TCSC and the transmission system. As a representative example the principles for boost voltage control will be outlined in the following. The steady-state behaviour of the TCSC, represented by the instantaneous voltage reversal approach, is illustrated in figure 8: Figure 8. TCSC steady-state conditions A necessary and sufficient condition for steady-state operation is that the charge provided by the line current between the voltage reversals must vanish. This is shown in figure 9a. Line current a) b) Figure 9 TCSC voltage boost control a) steady state b) increasing boost level c) decreasing boost level When the voltage reversals are phase advanced relative the line current from their steady-state positions then the charge from the line current will cause the capacitor voltage to increase between each reversal as shown in figure 9b. The boost voltage increase is proportional to the line current amplitude and the time deviation from its steady-state position. Similarly, as indicated in figure 9c, the capacitor voltage decreases between each voltage reversal when the instants of voltage reversal are phase retarded relative the line current. Thus, one way of characterising the TCSC from a control point of view, is to consider it as a controlled boost voltage source that has the displacement of voltage reversal instants as its input signal and the voltage boost as its output signal. It is evident from figures 9b-9c that the system ideally, i.e. disregarding from circuit losses, is integrating. Therefore some kind of boost controller is required. The main character of the controller simply is proportional gain, although in a practical implementation would require some integrating part to compensate for the circuit losses. boost response | | reference for boost P(I) |—+ displacement of reference voltage reversal instants Figure 10 Outline of voltage boost controller The SVR control system has been implemented in a DSP-based standard electronic system for HVDC and SVC control (ABB 'MACH’). Tests were performed in a real-time simulator (Transient Network Analyzer, TNA) at Transmission Technology Institute, Raleigh. The system studied is defined in (7): the often used 'IEEE 1'st benchmark model for SSR studies’. The simulator model involves a fully represented synchronous generator model together with its turbine-generator shaft system, which exhibits five torsional modes with mechanical resonance frequencies 15.7, 20.2, 25.5, 32.3 and 47.5 Hz (corresponding frequencies on the stator side are 44.3, 39.8, 34.7, 27.7 and 12.5 Hz). The generator is connected to an infinite bus via a radial, series-compensated transmission line. In figure 14 the network data are given. The degree of compensation is selected to 75 % of the line reactance. The resulting electrical resonance frequency is 40.3 Hz and with these data conventional series compensation destabilizes the 15.7 and 20.2 Hz (rotor side frequency) torsional modes. Ree st ee ates >" | source int oo turbine- j]enerator jen —trafo line shat system . imp bus Figure 14 IEEE first benchmark model for SSR studies The simulator set-up was varied in order to check different aspects of the SVR control concept, specifically with respect to its SSR mitigation capability. In the laboratory the important properties of the scheme, like its virtual impedance response characteristics etc., could be verified. Reasonable agreement between the expected behaviour from the small-signal models and the measured characteristics of the TCSC was obtained in the simulator. In this paper only one example of study results from the TNA study will be presented. The experiment in question indicates that the TCSC inhibits the destabilisation of the torsional modes, which may occur when a generators is connected through a radial line that is heavily compensated by fixed series capacitors. Figure 15 shows the recorded torsional angle of the shaft connecting the exciter and the generator in the TNA model. Initially the system was operating in steady-state with the TCSC in SVR control mode. The system was stable and the angular displacement between generator and exciter was very small. Then the thyristors in the TCSC were blocked at time ty and the system operated with fixed series compensation. This caused the 15 and 20 Hz torsional modes to become unstable and uncontrolled torsional oscillation started to build up. At time to the TCSC control was activated again. The TCSC control system cancelled the condition for torsional instability and the oscillatory modes were damped as for an uncompensated line. The torsional oscillation decreased and the angular displacement returned back towards a steady-state equilibrium. Figure 10 presents the general outline of a boost controller based on the above description. The advantage of this approach is that the transfer function of the system is extremely simple and only contains the sampling frequency and the line current amplitude. The inherent non-linearity that is related to the use of the thyristor turn-on angle as input signal has been eliminated. The description is /inear (for constant line current) and independent of the boost level. 5. How can the voltage reversals be directly controlled? It has been shown in the above sections that the key quantity to be controlled in the TCSC is the instant of voltage reversal, i.e. the instant of capacitor voltage zero- crossing or equivalently the instant of maximum thyristor current. Once this quantity is well controlled then the TCSC boost voltage can easily be regulated and the virtual impedance of the TCSC exhibits a character that is suitable for SSR mitigation. The delay from thyristor turn-on to the conduction interval midpoint depends on the line current and the capacitor voltage at turn-on. It is possible to estimate this delay from measurements and compensate the time delay as outlined in figure 11a. 1 a phaxa __, correction Ug - time & 4 Thyristor —iA\ current | ‘om | ‘start tev a) b) Figure 11 a) outline of time-correction circuit b) thyristor current for varying conditions in the TCSC The time correction circuit measures the capacitor voltage and the line current and estimates in each moment, tr, the capacitor voltage zero-crossing time, tp, assuming that the thyristor would be triggered immediately at tr. The trigger pulse is released when the estimated time, tp, coincides with the reference time trey=tstart+to. The result of this action of the time-correction circuit is that the thyristor is triggered at an instant that depends on the state variable conditions. The resulting thyristor current peak (capacitor voltage zero-crossing) instant however is kept constant for any combination of conditions. This function is illustrated by figure 11b. 6. Synchronous Voltage Reversal (SVR) mode of operation The reference time instants for capacitor voltage zero-crossings are derived from the line current by means of a PLL (figure 11a). The latter provides start-pulses used by the time-correction circuit twice per mains cycle for each TCSC phase. The time-correction circuit handles the inherent non-linearities of the TCSC main circuit. The bandwidth of the PLL is selected so that it responds to normal frequency variations in the network but does not respond to variations which are related to SSR currents. Thus mechanical vibrations in the shaft system do not affect the startpulses which remain at positions determined by the boost controller. This means that the virtual impedance of the TCSC appears resistive-inductive as described in section 3. This mode of operation constitutes the Synchcronous Voltage Reversal (SVR) mode of operation. Figure 12 presents the generic characteristics of the virtual impedance of a TCSC operating in the SVR mode. Three frequency bands can be identified: © power control frequency band e transition frequency band e SSR frequency band virtual reactance 4 “fy fixed capacitor Figure 12. Virtual reactance of TCSC operating in SVR mode The power control frequency band in the stator co-ordinate system embeds the rated system frequency 50 or 60 Hz. In the rotor co-ordinate system of the generator this frequency band appears close to zero. For components in this frequency range the TCSC provides capacitive controllable reactance. The SSR frequency range covers the frequencies in which the torsional mechanical oscillation modes may appear. Typically torsional vibrations appear in the frequency range 15-45 Hz. In the stator coordinate system these frequencies are translated by the rotational speed of the generator and they appear as side bands to the rated frequency of the mains. SSR build-up is prevented if the TCSC exhibits an inductive virtual impedance in this frequency range. The transition frequency band connects the two different frequency ranges described above. In this region the PLL response to line current disturbances decreases due to the parameters selected for the inner PLL frequency controller. The transition frequency band can moved be by appropriate tuning of the PLL. Using the approach described above the boost level can be controlled without any restrictions by some higher-level controller that acts for any power system related purpose without changing the virtual impedance of the TCSC in the SSR frequency range. The configuration is outlined in figure 13 'L uc Figure 13 Outline of total TCSC control system Finally it should be noted that the time-correction circuit releases the thyristor trigger pulses according to an algorithm that uses the measured capacitor voltage. Therefore the resonance conditions that may arise in a angle-based trigger pulse generating system are inherently avoided. Further the approach can easily incorporate a limiting feature for the capacitor voltage at turn-on, whereby it becomes reasonable to use a small inductance in the thyristor branch. 7. Modelling and validation The SVR scheme outlined in the above sections features a number of promising properties related to TCSC control in general and SSR aspects in particular. An extensive study has been performed of the concept. Small-signal models have been developed (MATLAB) and validated by comparison with time-domain models (EMTP). Control system tuning basically has been performed in MATLAB making use of the frequency-domain (eigenvalue) description that can be obtained from the small-signal model. Studies of the virtual impedance have hean invectinatad in a cimilar wav angle gen-exc (deg) Figure 15 SSR performance of TCSC 8. Conclusions and outlook The SVR concept for TCSC control has been described is this paper. It has been shown that a control system based on this principle can operate with varying voltage boost level, constantly exhibiting a virtual impedance in the SSR frequency range that prevents build-up of torsional oscillations. The SSR mitigation capability is inherent to the trigger control mechanism, which involves a time-correction circuit that permits direct control of the instants of voltage reversals. The concept has been implemented and tested in a real-time simulator. The results obtained show that the TCSC using the proposed control approach has the potential to realise series compensation, even at high degree of compensation, without restrictions due to SSR. 9. References 1. L. Angquist, B. Lundin, J. Samuelsson: Power Oscillation Damping Using Controlled Reactive Power Compensation - a Comparison Between Series and Shunt Approaches: IEEE Trans on Power Systems, Vol. 8, No. 2, May 1993, pp 687-700. 2. M. Noroozian, G. Andersson: Damping of Power System Oscillations by use of Controllable Components, paper 94 WM 064-6 PWRD, IEEE PES Winter Meeting 1994 3. M. Noroozian: Exploring Benefits of Controllable Series Compensators in Power Systems. Thesis Dept. of Electr. Power Eng., Royal Inst. of Technology, Stockholm 1994 4. N. Christl, W. Feldmann, R. Hedin,P. Luetzelberger, M. Pereira, K. Sadek: An Advanced Series Compensation Scheme Incorporating Power Electronics and Novel Control and Protection Strategies for AC Transmission Systems, T&D conference, Dallas, September 1991 S. G. Jalili, R. H. Lasseter, |. Dobson: Dynamic Response of a Thyristor Switched Capacitor, paper 94 WM 065-3 PWRD, IEEE PES Winter Meeting 1994 B. L. Agrawal, R. A. Hedin, R. K. Johnson, A. H. Montoya,B. A. Vossler: Advanced Series Compensation (ASC) Steady-State, Transient Stability and Subsynchronous Resonance Studies, FACTS Conference, Boston, May 18-20, 1992 IEEE Subsynchronous Resonance Task Force of the Dynamic System Performance Working Group, Power System Engineering Committee: First Benchmark Model for Computer Simulation of Subsynchronous Resonance, IEEE Trans on Power Apparatus and Systems, Vol. PAS-96, No.5, Sept/Oct 1977 DESIGN AND COMMISSIONING OF THE GE/GNB BATTERY ENERGY STORAGE SYSTEM AT VERNON, CA N.W. Miller, R.S. Zrebiec R.W. Delmerico GE Power Systems Engineering Department Schenectady, NY 12345 USA Abstract — Momentary and sustained power interruptions are some of the most difficult and important power quality problems facing many industrial and commercial users. Battery energy storage systems: (BESS) have the potential to provide versatile solutions to this problem for utility, industrial and commercial applications. This paper describes the design and commissioning of a5 MVA, 2.5 MW- hour BESS which is now in operation at the GNB Battery Recycling Plant in Vernon, California. The BESS at Vernon provides the required power combined with both voltage and frequency control to allow the plant to tolerate disconnection from the utility grid without suffering unacceptable impacts on critical loads. INTRODUCTION A 5 MVA, 2.5 MW-hour Battery Energy Storage System (BESS) was placed in service at the GNB Battery Recycling Plant, Vernon, California in November, 1995. The primary function of the Vernon BESS is to maintain the critical process loads during outages resulting from disturbances external to the plant. To accomplish this, it is installed at the 4160V level of the plant power distribution system, in parallel with the existing loads. The BESS is designed to work with the existing plant control system to automatically shed all non-critical loads as soon as possible after an incident. This permits the critical loads of up to 2.5 MW (mostly large induction motors) to operate for up to one hour. This time is necessary for the plant to safely shutdown its critical processes. Provision is made for transfer back to the utility feed if utility power is restored before the end of the one hour period. A secondary function of the system is to reduce the plant demand charges. This is accomplished by utilizing a portion of the battery capacity to supply energy to the plant during peak load periods. G. Hunt GNB Industrial Battery Lombard, IL USA This paper will provide an overview of the converter and battery system and show key test results obtained during commissioning at Vernon. A detailed description of the converter design is planned for future publication. OVERVIEW OF THE INSTALLATION The system consists of the following major items: 1. A dedicated Battery Energy Storage System building. 2. Two strings of batteries, complete with manual disconnect switches and fuse protection. 3. Battery monitoring control cabinet providing peak shaving and state-of-charge control. 4. Personal computer interface to the battery monitor for data display, battery maintenance and data acquisition. 5. A power conditioning system (PCS), which provides bi- directional power conversion between the ac and dc systems. 6. Station control for sequencing and control of the power converters. 7. Remote operator’s panel located in the plant control room. 8. Fused main BESS disconnect switch. 9. Power factor correction capacitors and harmonic filter to meet IEEE 519. [1] 10.Relay panel responsible for detecting a utility outage and supervising the operation of the main plant service breaker. Three key modes of operation exist: © On Utility - which defines the normal state when active power for the plant loads is supplied by the utility and the BESS is idle, charging or peak shaving and managing reactive power for the plant. e Isolated - which defines the emergency state when power for the plant loads is supplied by the BESS and the utility is disconnected. e Resynchronizing - which defines the process whereby the isolated plant is reconnected to the utility. A simplified one-line diagram of the system is shown in Fig. 1. Battery System Battery ' Monitor [ ‘ | Personal : Computer 0 PCS i aun a at tation de : Control ¥ ¥ : Remote ‘ Operator's ww Panel nM BESS Disconnect Critical Loads Relay Plant + Breaker paneh 4160V Utility Feeder Fig. 1. Simplified BESS One-Line Diagram. The entire Vernon BESS, including the batteries is enclosed in a 131'x25’ building with the filter, transformers and disconnect switch located outdoors. The battery building is shown in Fig. 2. Harmonic Filters System Rating The system is designed to operate for 10 seconds at a maximum plant demand of 5 MVA immediately after the transition to isolated mode. This capacity exceeds the total existing and projected loads at the plant with some margin. Upon sensing a loss of utility voltage: 1. the incoming circuit breaker is opened, 2. the existing plant control system will shed all but the critical load, and 3. the BESS will carry the critical loads, up to 2,500 kW for one hour. SUMMARY OF SYSTEM RATINGS FOR GNB VERNON 4160 Vrms L-L Nominal Current Rating _ 348 Arms Nominal Power Rating 2500 kVA continuous 5000 kVA for 10 sec. Nominal DC Voltage Rating 756 Vde (660 - 900 Vdc range) Power Conditioning System The PCS part of the BESS consists of a voltage source inverter which is designed to operate as either an inverter when discharging the battery or as a rectifier when charging. The PCS is designed with self-commutating static switches capable of supplying the reactive power needs of the system.[2] The ac waveform has some resultant harmonic content which is filtered to meet IEEE 519 standards. The 6-pulse converters of the PCS are arranged in pairs. A simplified circuit diagram of one Power Converter Pair (PCP) is shown in Fig. 3. Each PCP forms a 12-pulse, PWM, bi-directional, voltage source GTO converter. Each GTO is paralleled by a reverse diode to give the converter the capability of handling power flow in both directions. The dc capacitor, CD, is necessary to absorb ac currents reflected by the converters on to the de bus. Fig. 2. Vernon Battery Building. 2 Phasor Diagram N 1A 2A —_ 1A * Transformer Type 2 + Fig. 3. 12-Pulse Power Converter Pair. Each 6-pulse converter is connected to a power transformer designed for static converter operation. The connections are arranged to provide an equivalent 12-pulse wave shape when OC Line Panel DC Link Capacitor connected to two 6-pulse converters operated with firing signals 30 electrical degrees apart. Three PCPs are connected in parallel to achieve the rating requirements for this application. Each PCP is connected to the power system through an ac contactor. The PCP converter hardware is shown in Fig. 4. The two 30” wide cabinets on the right hand side contain the two 6- pulse GTO converters. The upper half of these cabinets contain the drive control hardware. The GTO bridge, gate drivers, blowers and energy recovery snubber circuit are mounted in the bottom half. The center 24” wide cabinet contains the dc link capacitor bank (CD) and protection. The left hand cabinet is the application specific dc line panel. This panel includes the dc link converter, capacitor charging circuit, V/O interface, control isolation transformers and miscellaneous control hardware. Theory of Operation For most operating conditions the BESS is equivalent to a voltage source behind the transformer reactance (X7) as shown in Fig. 5. The PCS generated voltage (Vg) is completely controllable within the current rating of the converter equipment. Consequently, the ac current can be supplied at any phase-angle relative to the terminal voltage (V7). This feature permits the BESS to generate real and reactive power in all four quadrants as indicated by the capability curve. The BESS power generating capability is limited by the thermal rating of the converters and the available battery. voltage. Overload capability will permit operation at higher currents for limited periods of time, as suggested by the dotted capability curve. = MM re 6-Pulse Converter 6-Pulse Converter Fig. 4. PCP Converter Hardware Line-Up. Reactive Power (kVAr) Rated | cae Converter a . Overload Capacity \, - 7 Capacity : * Active Power (kW) Charging * ‘Discharging inductive Equivalent Circuit vy : *t Yr [Distribution O —s Network It Phasor Diagram _‘B __ ty vp Fig. 5. Active and Reactive Power Capability. A simplified block diagram of the control system is shown in Fig. 6. Terminal voltage magnitude and power control loops are included with the PCS. Power and voltage orders are provided by the Station Control. Station Control Control of the PCS to meet the various modes of operation is provided by the station level control as shown in Fig 6. The control consists of a microprocessor controller for regulator functions and a PLC for sequencing and protection. When operating on-utility the voltage order is derived from a closed loop var regulator which maintains the PCS at a desired power factor. The power order follows the charging needs of the battery or the operator can schedule the system to automatically reduce the plant demand charges. When isolated from the power grid the voltage order is adjusted to maintain nominal plant voltage (4160V) and the power order is dynamically adjusted to hold rated frequency (60 Hz). When resynchronizing, voltage order is adjusted to match measured utility voltage and plant frequency is adjusted to match measured utility frequency and __phase-angle. Synchronizing with the utility is supervised by a standard synchronism check relay. Battery Monitor Control The battery monitoring control performs five major functions: 1. calculates the state-of-charge of the battery, 2. provides for battery charging and discharging control, 3. monitors the health and status of the battery, 4. records battery operation for future optimization and warranty management, 5. detects ground faults. The Battery Monitoring function is implemented in a PLC, working with the Operator Interface Computer. The computer consists of an industry standard PC running a graphical interface program for data storage and display. Batteries Valve regulated lead-acid (VRLA) maintenance-free batteries are used. Two battery series strings are connected in parallel to provide a nominal amp-hour rating of 2.5 MW- hour. Each string includes a fused disconnect sized to allow operation with one string out-of-service. The electrical center of each battery string is high resistance grounded. A string consists of 378 modules, each rated 2V and connected in series to make a nominal 756V string. The modules are arranged in stacks. A single stack of batteries . consists of eight modules separated and supported by 4' steel “T” beams. Each module measures 42.5” x 26.4” x 8.6” for an Station Control Phase Reg. Measured Mode Fig. 6. BESS Control System. 4 overall stack height of about 6’. Each stack assembly has a Fig. 8 is an oscillogram which shows the response of the standing weight of about 6360 lbs. A total of 48 stack system during the breaker trip test. The battery was initially assemblies arranged in two rows are required for each string. charging at a low rate corresponding to about 480 kW. While A typical stack assembly is shown in Fig 7. *SPD: S mm/s “TIME SCALE: 2 Fig. 7. Close-up of Battery String. Filter The 1400 kvar filter is sized to correct the critical plant load to unity power factor. The branches are tuned to the 5th, 7th and 11" harmonics. The filter is designed to meet IEEE Standard 519 [1] under all operating conditions. The BESS may be run in isolated mode without the filter. Relay Panel This panel consists of standard utility grade protection relays designed to monitor the point of utility connection. The control logic will trip the main plant breaker if the utility feeder is faulty. The following conditions are detected: e Faulted phase detection ¢ 3-phase power interruption ¢ 1-phase power interruption © Over/ under frequency While the plant is isolated the relay panel will detect when three-phase utility feeder voltage is restored. If the operator then requests a resynchronization, the relay panel will supervise the breaker closing using a synchronism check relay. All relays are self resetting to allow for unattended automatic operation. FINAL COMMISSIONING TEST RESULTS Acceptance tests of the Vernon system were completed on November 5, 1995. The tests included a total interruption of the utility power feeding the plant. The critical plant loads, totaling 2100 kW, were transitioned to the battery system and ran in isolated mode for about 30 minutes. The plant loads Fig. 8. Response of BESS and Plant During Isolation from the System. were then automatically resynchronized with the utility feeder. (a) Battery Voltage The critical load consists of about 25 induction motors plus (b) Plant Voltage lighting and control. Four of the motors, totaling 1600 hp, are (c) PCS Watts connected at the 4160V bus. The balance of the motors, about (d) Battery String #1 Current 1400 hp, are connected at 480Vac. (e) Battery String #2 Current (f) Plant Frequency (g) BESS Line Current at 4160V Bus (includes filter) charging the BESS is also compensating the reactive component of the plant load to maintain unity power factor at the point of utility connection. This is done to maximize the power available for charging the battery. The total reactive compensation while charging, including the filter component, is about 2200 kvar. The total plant load prior to the test is about 3000 kW (excluding the BESS charging kW) and includes about 2100 kW of critical loads. To simulate a power interruption the plant breaker was manually tripped. Notice that the critical plant loads immediately transition to the BESS following the manual breaker trip. To support these loads the battery string current increases to about 1300 amperes and the battery voltage drops slightly. Since the BESS regulators maintain the proper voltage magnitude and frequency the power output naturally follows the needs of the plant loads. From the plant perspective the breaker trip test was essentially bumpless. All critical loads including sensitive electronic equipment such as PCs were unaffected by the transition. A plot of the measured voltage waveform and harmonic content while the plant was isolated is shown in Fig. 9. Readings - 11/08/95 14:11:20 Voltage 200 100 Volts : 10.42 12.51 14.59 -100 ied Time mS 190 Volts 10 rms 0 °pe 24 6lUtlCUlCUO COO 13 $s 79 HBDE NT YDPUHs Ww H Harmonic Number Fig. 9. BESS Voltage Waveform and Harmonic Content Measured During Isolated Operation. Motor Starting While the plant was isolated a 100 hp motor was started. An oscillogram of this test is shown in Fig. 10. The test proceeded without difficulty. *REALTIME RECORDER . f SaAmi Fig. 10. Response of BESS and Plant During Motor Starting. (a) Battery Voltage (b) Plant Voltage (c) PCS Watts (d) Battery String #1 Current (e) Battery String #2 Current (f) Plant Frequency (g) BESS Line Current at 4160V Bus (includes filter) Resynchronizing Once utility feeder voltage is present the BESS may be requested to reconnect the isolated plant load with the utility. Resynchronizing requires that the instantaneous voltage across the open plant breaker be reduced to zero. To accomplish this the isolated plant voltage magnitude, frequency and phase- angle are adjusted to match the utility. The breaker is closed if the voltage is within +10% and +6° for a two second period. An oscillogram of the resynchronization test is shown in Fig. 11. The isolated plant load at the time of the test is about 2300 kW (the plant loading is increased slightly during the test). The battery voltage before resynchronization is about 740V and the string current is about 1550 amperes. Immediately following the breaker closing the BESS output power is reduced to smoothly transition the plant load back to the utility feeder. SUMMARY This installation is commissioned and performing well. Although the primary function of the Vernon BESS is to maintain the critical process loads, the system will also serve as a demonstration of the practicality of the BESS technology to power quality problems. [3] ACKNOWLEDGMENTS The authors wish to recognize the contributions of W. Hill, C. Harbourt and D. Wanner (converter design), C. Wegner and M. Cardinal (system software), and M. Jesko (battery system). The authors are grateful to these and many others whose contributions are essential to a project of this magnitude. REFERENCES {1] IEEE Std. 519-1992, “IEEE Recommended Practices and Requirements for Harmonic Control in Electric Power Systems,” IEEE, NY, NY, April 12, 1993. [2] L.H. Walter; “10 MW GTO Converter for Battery Peaking Service,” IEEE Trans. Ind. Appl., Jan/Feb. 1990, Vol. 26 #1, pp. 63-72. [3] N.W. Miller, R.S. Zrebiec, R.W. Delmerico, G. Hunt; “Battery Energy Storage Systems for Electric Utility, Industrial and Commercial Applications,” Proceedings PCIM/Power Quality/Mass Transit 1994. ss *SPD: S mm/s "TIME SCALE: 200.0 SES eee eee ee ee eS eee Fig. 11. Response of BESS and Plant During Controlled Resynchronization with the Utility Grid. (a) Battery Voltage (b) Plant Voltage (c) PCS Watts (d) Battery String #1 Current (e) Battery String #2 Current (f) Plant Frequency (g) BESS Line Current at 4160V Bus (includes filter)