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Home My WebLink AboutS. Intertie Phase 1 Jan 23-1996 PROJECT NO. 120293-01 ) y VLOMER ISSUED TO: es NGINEERS COPY NO: CHUGACH ELECTRIC ASSOCIATION, INC. CONTRACT NO. 95-208 SOUTHERN INTERTIE ROUTE SELECTION STUDY PHASE 1 JANUARY 23, 1996 DRAFT STUDIES SECTION REPORT VOLUME | OF Ill CAVE EGEIVE|) FOR INFORMATION CONTACT: IAN 2 § 2g0¢ JAN 69 Wee = 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 Alaska Industria! Development and Export Authority 3. SOUTHERN INTERTIE ROUTE SELECTION STUDY PHASE 1 SYSTEM STUDY REPORT SECTION VOLUME I OF III TABLE OF CONTENTS ELECTRICAL SYSTEM STUDY SUMMARY tt 1.2 1.3 1.4 INTRODUCTION ELECTRICAL SYSTEM ALTERNATIVES ELECTRICAL SUMMARY AND CONCLUSIONS SYSTEM STUDY SUMMARY ELECTRICAL SYSTEM STUDIES 2.1 2.2 2:3 2.4 2.5 GENERAL SYSTEM STUDIES, CRITERIA AND ASSUMPTIONS LOAD FLOW STUDIES ALTERNATIVE N-1 ANALYSIS ALTERNATIVE DYNAMIC STABILITY ANALYSIS ELECTRICAL REQUIREMENTS 3.1 3.2 3.3 3.4 3.5 3.6 EXISTING LINE PARALLEL EXISTING LINE ENSTAR ROUTE TESORO ROUTE BELUGA ROUTE BATTERY ENERGY STORAGE SYSTEMS APPENDIX A - ASCC PLANNING CRITERIA APPENDIX B - N-1 VOLTAGE VIOLATION APPENDIX C - BELUGA ROUTE CORRESPONDENCE VOLUME II OF III - LOAD FLOW DIAGRAMS VOLUME III OF III - STABILITY ANALYSIS PAGE I-1 1-2 1-4 1-7 II-1 II-3 II-9 I-18 TI-24 Til-1 Ill-6 I-12 I-17 Il]-22 Ill-27 SOUTHERN INTERTIE ROUTE SELECTION STUDY PHASE 1 SYSTEM STUDY REPORT SECTION VOLUME I OF III TABLE OF TABLES Table 1: Table 2: Table 3: Table 4: Table 5: Table 6: Table 7: Table 8: Table 9: Table 10: Table 11: Table 12: Table 13: Table 14: Table 15: Table 16: Table 17: Table 18: Table 19: Table 20: Alternative Load Flow and Summary Maximum Available Power for Transfer from the Kenai to Anchorage Scheduled Power for Transfer from the Kenai to Anchorage Alternative 1 - Do Nothing - Load Flow and Loss Summary Alternative 1B - Add Shunt Capacitors - Load Flow and Loss Summary Alternative 1C - Convert to 230kV - Load Flow and Loss Summary Alternative 2 - Parallel Existing at 138kV - Load Flow and Loss Summary Alternative 2A - Parallel Existing at 138kV with Overhead Crossing Bird Point - Load Flow and Loss Summary Alternative 2B - Parallel Existing at 230kV - Load Flow and Loss Summary Alternative 2C - Parallel Existing at 230kV with Overhead Crossing at Bird Point - Load Flow and Loss Summary Alternative 3 - Enstar Route at 138kV - Load Flow and Loss Summary Alternative 3A - Enstar Route at 230kV - Load Flow and Loss Summary Alternative 4 - Tesoro Route at 138kV - Load Flow and Loss Summary Alternative 4A - Tesoro Route at 230kV - Load Flow and Loss Summary Alternative 5 - Beluga Route at 138kV - Load Flow and Loss Summary Alternative 5A - Beluga Route at 230kV - Load Flow and Loss Summary Summary of N-1 Analysis for the Southern Intertie Existing System 2015 with Initial 7OMW Transfer from Hope Summary of N-1 Analysis for the Southern Intertie Parallel Route 138kV - 2015 with Initial 125MW Transfer Summary of N-1 Analysis for the Southern Intertie Parallel Route 230kV - 2015 with Initial 125MW Transfer Summary of N-1 Analysis for the Southern Intertie Enstar Route 138kV - 2015 with Initial 12S5MW Transfer PAGE II-2 Il-2 II-10 TI-11 I-12 I-12 I-13 I-13 TI-14 II-14 II-15 Tl-15 II-16 II-17 I-17 II-18 I-19 I-20 II-21 TABLE OF TABLES (continued) Table 21: Summary of N-1 Analysis for the Southern Intertie Enstar Route 230kV - 2015 with Initial 125MW Transfer Table 22: Summary of N-1 Analysis for the Southern Intertie Tesoro Route 138kV - 2015 with Initial 125MW Transfer Table 23: Summary of N-1 Analysis for the Southern Intertie Enstar Route 230kV - 2015 with Initial 125MW Transfer TABLE OF FIGURES Figure 1: Color Map Figure 2: Area Load, Generation & Transfers - Winter 1997 Figure 3: Area Load, Generation & Transfers - Winter 2015 Figure 4: Area Load, Generation & Transfers - Summer 1997 - Maximum Transfer from Kenai Figure 5: Area Load, Generation & Transfers - Summer 1997 - Transfer to Kenai Figure 6: Electrical Study - Existing Route Figure 7: Parallel Existing Route with 138kV Figure 8: Parallel Existing Route with 230kV Figure 9: Electrical Study - Parallel Route Figure 10: Enstar Route 138kV Figure 11: Enstar Route 230kV Figure 12: Electrical Study - Enstar Route Figure 13: Tesoro Route 138kV Figure 14: Tesoro Route 230kV Figure 15: Electrical Study - Tesoro Route Figure 16: Beluga Route 138kV Figure 17: Beluga Route 230kV Figure 18: Electrical Study - Beluga Route PAGE I-21 I-22 I-23 PAGE 1-6 II-5 II-6 II-7 II-8 T-5 Iil-9 Til-10 Iil-11 Iil-14 I-15 IIl-16 I-19 TII-20 I-21 TII-24 TI-25 TIl-26 L 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: L 2. 3. 4. The secure power transfer limits of each study alternative under normal operating conditions; The post-contingency emergency power transfer limits of each alternative; 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. This report presents the findings of the electrical system studies of: i 2. 3: The existing intertie; The new intertie options; and 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: 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); 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 listing of the major equipment requirements for each alternative. PEI-HLY 23-017 (01/23/96) 120293-01/rh 1-1 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 (01/23/96) 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-5. PEI-HLY 23-017 (01/23/96) 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 70MW due to high losses and voltage drop. ® Construction of a 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 190MW. All four of the 138kV alternatives studied exhibit similar operational characteristics. 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. 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 alternative 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 capability. ® 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 reconductoring the 4.45 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. Electrical performance is summarized in Table 1. Figure 1 shows the routes for the alternatives modeled in this study. Secure transfer limits consider both interties in service. PEI-HLY 23-017 (01/23/96) 120293-01/rh 1-4 Table 1: Alternative Load Flow And Loss Summa Alternative | Secure Transfer Limit (MW) omy [| er | E rtthe Pores = ter Mecite ising |B | stesrer [tee 12s N/A 90/115 a spate te tet ra fe eee ead “Alternative Limit Codes 1 = Limited by conductor thermal rating (ampacity) 2 = Limited by reasonable generation mix, spinning reserve on the Kenai and transmission losses. 3 = Limited by voltage drop 4 = Limited by system stability concems LFRESULT.XLS 1/10/96 I \E on. | 7 ez \e ewan IS ee {D)) I I I j ie 2 SS: . ARS. ‘gr WO SUBSTATION GENERATING PLANT 15 KV 69 KV a 230 KV \ ? LEP KENAI ¢ . ae ; a eee Sy y YZ oe R Nee ore ito mallee SOLDOTN SYK ‘{ ae N Q on : / 4 la ? WS ZR. ENSTAR ROUTE === — P PARALLEL ROUTE = = = = SOLDOTNA (HEA) cs wa), TESORO ROUTE ———— SOLDQTNA ; yO (AEGXT) WO . NS X NOTE: LOCATION FOR ELECTRICAL IS APPROXIMATE f——7 7 ; Ra IS FIGURE #1 ELECTRICAL STUDY INTERTIE ROUTES 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 125MwW 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 Table 1 on page 5. 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 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 increase substantially. For the 125MW flows used in the study, the losses increased from 6.9MW to 25MW. PEI-HLY 23-017 (01/23/96) 120293-01/rh 1-7 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 voltage 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. This alternative is not feasible as a stand-alone modification due to the high losses and low voltages for increased power transfers. Upgrades of the 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, Lawing, Summit Lake and Quartz Creek. 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 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 PEI-HLY 23-017 (01/23/96) 120293-01/rh 1-8 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 795 Drake at 230kV is 3583MW. Maximum summer loading of 190MW 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 190OMW. 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. PEI-HLY 23-017 (01/23/96) 120293-01/rh 1-9 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 bring generation on- line. 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 40MW 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 (01/23/96) 120293-01/rh 1-10 I. 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 (1/23/96) 120293-01/rh Il-1 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 Anchora: Kenai System (MW) Year Maximum | Projected Normal Additional Spinning Available Generation Load Losses Losses Reserve Transfer Summer 1997 2478 | 47, | 2 8190.8 iSummer 2015 [| 247.8 [| 51 | 2 0 186.8 Winter 1997 2478 | 85 | #5 | 0 152.8 [winter 2015] 247.8 [4 1888 e 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 Anchora: Kenai System (MW) Year Generation | Projected Normal Additional Spinning Available Load Losses Losses Reserve Transfer Summer 1997 (1)| 2298 | 47, | 2 Tt 1568.8 Winter 1997 _(1 2298 | 85 | SST 1228 Winter 2015 | 2478 Tet 125.8 | (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. e PEI-HLY 23-017 (1/23/96) 120293-01/rh l-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 New transmission interties would be 795kcmil ACSR Drake conductor. 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 12OMW. @ 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 (1/23/96) 120293-01/rh Il-3 Assumptions For this study the following assumptions were used in the analysis of the alternatives: Fairbanks Area is defined as GVEA and FMUS service areas. Anchorage Area is defined as the AML&P, MEA and the CEA service areas out to Portage. Kenai area is defined as the HEA, SEA and CEA service area to include Hope. Transfers are defined as the flows on the existing intertie between Hope and Portage and the flow on the new intertie. The swing bus for power flows is Beluga Unit 3. For this study, “Maximum Secure Transfer” is defined as the maximum amount of power that can be transferred with the system “intact” and “pre-contingency” under steady-state conditions with consideration given to system stability concerns according to ASCC Criteria Number 2 - Contingencies. The “Emergency Transfer Limit” is defined as the maximum amount of power that can be transferred with the system “intact” and under “post-contingency” conditions. 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 (1/23/96) 120293-01/rh -4 GENERATION FAIRBANKS AREA 40MW* AT DOUGLAS ANCHORAGE AREA 105MW* ARRIVES AT ANCHORAGE Includes Existing and New Interties 123MW* TRANSFERRED KENAI AREA 229.8MW “Values are approximate FIGURE 2: AREA LOAD, GENERATION AND TRANSFERS WINTER 1997 II-5 GENERATION FAIRBANKS AREA 79MW* AT DOUGLAS ANCHORAGE AREA 524.5MW 82MW* ARRIVES AT ANCHORAGE ncludes Existing and New Interties 125MW* TRANSFERRED KENAI AREA 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 Includes Existing and New Interties 181MW* TRANSFERRED KENAI AREA 247.8MW “Values are approximate FIGURE 4: AREA LOAD, GENERATION AND TRANSFERS SUMMER 1997 - MAXIMUM TRANSFER FROM KENAI II-7 GENERATION FAIRBANKS AREA ANCHORAGE AREA 49MW* TRANSFERRED ncludes 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). 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. 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. 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 PEI-HLY 23-017 (1/23/96) 120293-01/rh l-9 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 9OMW. 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 Load Exist Tie | New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By (MW) MW (MW) Ampacity / 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 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 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 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 transformer and associated breakers at Soldotna, and replacement of the 4.55 miles of Brahma conductor. PEI-HLY 23-017 (1/23/96) 120293-01/rh I-10 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 added as SVCs to allow 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. The 4.55 miles of Brahma conductor would require reconductoring with 556.4kcmil Dove or 795kcmil Drake to upgrade the line’s thermal rating from 70MVA to 145MVA. Table 5 summarizes the performance of this alternative for the load years 1997 and 2015. The emergency limit of the line would be expected to be about 145MW, due to voltage drop, but the actual limit was not defined because the losses appear to make this alternative undesirable. 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. Table 5: Alternative 1B - Add Shunt Capacitors - Load Flow And Loss Summary Transfer Exist Tie | New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By MW) MW) (MW) a. in ee a | 122 | 260 | wa | ~145 | Voltage Drop line with “ soa on STIE1SB | aos | 119 | 255 | wa | -145 | Voltage Drop capacitiors PEI-HLY 23-017 (1/23/96) 120293-01/rh l-11 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 Transfer Exist Tie | New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By (MW: MW: (MW) isting line Stabiltity / 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. 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. 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. Table 7: Alternative 2 - Parallel Existing at 138kV - Load Flow And Loss Summary Transfer Exist Tie | New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By (MW: MW: (MW) See, | earn [oor [am [a [co [om [come | existing line mPorage | &xis1984 | 205 | tas | 40 | Generaton PEI-HLY 23-017 (1/23/96) 120293-01/rh I-12 ALTERNATIVE 2A - PARALLEL THE EXISTING LINE WITH A NEW 138KV TRANSMISSION LINE WITH AN OVERHEAD 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. 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 Overhead Crossing at Bird Point - Load Flow And Loss Summary Transfer Exist Tie] New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By (MW) (MW) (MW) existing line with 138kV 5 prgeamg | —&xt5136a | 20s | ts | 47 | a4 | 104 | Generation 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. Table 9: Alternative 2B- Parallel Existing at 230kV - Load Flow And Loss Summary Transfer Exist Tie |] New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By MW MW) _|_(MW) = EE : i existing line with 230kV : fh PRA EX15230A 2015 125 2.8 190 Generation 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. PEI-HLY 23-017 (1/23/96) 120293-01/rh I-13 ALTERNATIVE 2C - PARALLEL THE EXISTING LINE WITH A NEW 230KV TRANSMISSION LINE WITH AN OVERHEAD 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. The crossing was modeled as overhead construction. 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 - Load Flow And Loss Summary Transfer Exist Tie | New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By (MW) (MW) (MW) existing line with 230kV 7 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, 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 Transfer Exist Tie} New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By MW) MW: (MW) PEI-HLY 23-017 (1/23/96) 120293-01/rh I-14 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 Transfer Exist Tie | New Tie Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By MW MW (MW) Eraarroute| ene72000 | seer | za | oo | 17 | 100 | caneraton | Generation 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 Transfer Exist Tie | New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By MW MW (MW) Nf Reemaee 1907 | 125 1.8 26 | 190 | Generation | ey TO15138J 2015 | 125 17 25 | 190 | Generation | 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 PEI-HLY 23-017 (1/23/96) 120293-01/rh W-15 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. The existing reactors at the Point Woronzof Substation would be used to neutralize the capacitance at that end. The existing 115kV line from Soldotna to Bernice Lake would not require any upgrades for this alternative. 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. Table 14: Alternative 4A -Tesoro Route at 230kV - Load Flow And Loss Summary Transfer Exist Tie | New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By MW) MW: (MW) Tesoro Route TO97230C 1997 125 1.3 1.3 190 Generation on T015230C 2015 | 125 | 17 13° | 190 Generation 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. PEI-HLY 23-017 (1/23/96) 120293-01/rh l-16 Table 15: Alternative 5 - Beluga Route at 138kV - Load Flow And Loss Summary Transfer Exist Tie | New Tie | Emerg. Alternative Load Flow Case Year (MW) Loss Loss Limit Limited By MW: MW) (MW) Beluga Route BA97138D 1997 190 Generation baal BA15138B 2015 190 ao 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. Table 16: Alternative 5A - Beluga Route at 230kV - Load Flow And Loss Summary Transfer Exist Tie | New Tie | Emerg. Altemative Load Flow Case Year (MW) Loss Loss Limit Limited By (MW MW, (MW) Geka Hee BA97230B 1997 124 1.0 190 Generation il BA15230B | 2015. | 122 09 | 190 Generation 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 (1/23/96) 120293-01/rh I-17 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 Treminal - 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. 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. 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 Buses Below Buses Above Lines Greater Than 0.95 per unit 1.05 per unit 100% Loading [Soldotna SVS- 1.059 |None East Terminal- 41 Soldotna SVS - 1.050 | Woronzof.-Mack. West Terminal Off-line See Page 1 Appendix B |Daves SVS - 1.099 136% of 146MVA ‘Lowest Voltage at rating PEI-HLY 23-017 (1/23/96) 120293-01/rh I-18 AML&PTap 230 - 0.906 pcg tine Beluga #8 Off-line Bradley Lake Units ‘Homer 69kV - 0.938 ‘None ‘None (Both) Off-line [Diam Rdg 69kV - 0.946 Bradley Lake-Soldotna None Soldotna SVS - 1.083 |Anch Pt-Diam Rdg Offline Daves SVS - 1.059 102% 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 Buses Above 1,05 per | Lines Greater Than 0.95 per unit unit 100% Soldotna SVS Off-line Homer 69 - 0.949 Bernice T1 - 0.943 Daves SVS Off-line Seward 69 - 0.939 SoldotnaSVS-1.090 [None sd Soldotna #1 Off-line None DavesSVS-1.058 [None sd i ’ 16 Buses Soldotna SVS - 1.054 See Page 2 Appendix B |Daves SVS - 1.094 Lowest voltage at University 34.5 - 0.939 16 Buses Soldotna SVS - 1.055 | Woronzof.-Mack. See Pg3 AppendixB |Daves SVS - 1.099 116% of 146MVA Lowest voltage at i University 34.5 - 0.933 Daves SVS - 1.080 Bradley Lake Units (Both) {Diam RDG69-0.946 |None (Off-line : Bradley Lake-Soldotna Off- line 102% of 68MVA Rating Existing Intertie Off-line None Soldotna SVS - 1.092 New Intertie Off-line Soldotna SVS - 1.077 |None (60Mvar Capacitor at Hope Daves SVS - 1.092 N-1 analysis was not performed for the Bird Point Alternative 2A. PEI-HLY 23-017 (1/23/96) 120293-01/rh I-19 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 _0. 95 ech oo ee SVS - 1.064 None Soldotna SVS - 1.076 {None Daves SVS - 1.075 Soldotna SVS - 1.079 |Woronzof.-Mack. oi of 146MVA Soldotna SVS - 1.070 ey Daves SVS - 1.060 None [Homer 69 - 0 0.938 i Kasilof 115 - Soldotna Anch Pt. 115 - 0. 947 A 130% to 147% of Homer 69 - 0.910 i i Qrtz 115 - Daves 115 101% of 145MVA Rating N-1 analysis was not performed for the Bird Point Alternative 2C. PEI-HLY 23-017 (1/23/96) 120293-01/rh Il-20 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 | oS Buses Below Buses Above 1.05 per | Lines Greater Than Soldotna SVS Off-line ernice T1 24.9 - 0.946 None lone None Soldotnas SVS - 1.077_|None . f Soldotna SVS - 1.092 |None Off-line Daves SVS - 1.055 East Terminal-West University 230 - 0.948 |Soldotna SVS - 1.090 Terminal Off-line Daves SVS - 1.063 Woronzof.-Mack. 101% of 146MVA rating ‘None Soldotna SVS - 1.082 Diam RDG 69 - 0.946 Off-line Homer 69 - 0 0.938 Bradley Lake-Soldotna Off- |Diam RDG 69 -0.913 {Soldotna SVS - 1.087 _|Kasilof 115 - Soldotna line Anch Pt. 115-0.942 |Daves SVS - 1.061 130% to 147% of Homer 69 - 0.905 68MVA Line Ratings four line sections) ‘None Existing Intertie Off-line ‘None Soldotna SVS - 1.098 New Intertie Off-line Seward 69 - 0.915 Soldotna SVS - 1.100 80Mvar added to University |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 Lines Greater Than _ 100% [None i (None Daves SVS Off-line Off-line East Terminal-West Woron.-Mack. 101% o! Terminal Off-line 146MVA rating Beluga #8 Off-line Off-line ‘Homer 69 - 0 0.936 PEI-HLY 23-017 (1/23/96) 120293-01/rh Il-21 Table 21 - Continued 130% to 147% of 68MVA Line Ratings (four line sections) Existing Intertie Off-line New Intertie Off-line Seward 69 - 0.903 None 90Mvar added to Universi 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 ine Outage Case Buses Below Buses eke 1.05 per | Lines Greater Than — 0.95 per unit 100% Soldotna SVS Off-line Bernice T1 24.9 - 0.949|Daves ave : 061 Daves SVS Off-line Bernice T1 24.9 - 0.949|Soldotna SVS - 1.066 Soldotna #1 Off line Soldotnas SVS - 1.066 {None Soldotna SVS - 1.067 Daves SVS - 1.057 Soldotna SVS - 1.063 ‘None Soldotna SVS - 1.094 | Kasilof 115 - Soldotna 130% to 147% of AnchPT 114 - 0. 947 68MVA Line Ratings Homer 69 - 0.937 four line sections) Soldotna SVS - 1, 075 Daves SVS - 1.105 PEI-HLY 23-017 (1/23/96) 120293-01/rh I-22 ALTERNATIVE 4A - TESORO ROUTE AT 230KV: Table 23 - Summary of N-1 Analysis for the Southern Intertie Enstar Route 230kV - 2015 with 125MW transfer Daves SVS Off-line None None Soldotna SVS - 1.064 [Daves SVS - 1.058 1.059 Off-line [Homer 69 - 0 0.938 Bradley Lake-Soldotna Off- |Anch Pt. 115-0.950 |Soldotna SVS - 1.098 line Diam RDG 69 - 0.920 Homer 69 - 0 0.912 Existing Intertie Offline [None____—————__—[ Soldotna SVS - 1.063 __ [None New Intertie Offline Soldotna SVS - 1.078 60Mvar added to Portage Daves SVS - 1.1065 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. PEI-HLY 23-017 (1/23/96) 120293-01/rh Il-23 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 70MW 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 (1/23/96) 120293-01/rh I-24 1. 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). 2. 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 H5 vs. W7B H5). More PEI-HLY 23-017 (1/23/96) 120293-01/rh I-25 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. W5SX 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 (1/23/96) 120293-01/rh Il - 26 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 (WSI H6A). In the Kenai area, with loss of the new intertie at 125MW 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 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. PEI-HLY 23-017 (1/23/96) 120293-01/rh Il-27 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). 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 PEI-HLY 23-017 (1/23/96) 120293-01/rh Il - 28 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 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 60MW, 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 PEI-HLY 23-017 (1/23/96) 120293-01/rh Il-29 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 (1/23/96) 120293-01/rh Il - 30 I. ELECTRICAL REQUIREMENTS 3.1 EXISTING LINE The following major equipment has been identified for the alternatives that modify the existing 115kV line. Figure 6 shows the existing line route. Alternative 1A - Convert Existing Route To 138kV Transmission Line Requirements | Equipment | C‘éRRaatingg’—S—sSCSCSC*d:=C Quantity Reconductor Girdwood -indian Section of |138kV, 900A, 795 Drake ACSR 4.45 miles 203kcmil Brahma Underground Transmission Line Soldotna Substation Requirements Power Transformer -115kV-138kV 150MVA Base Rating / 200MVA Top 1 each Rating Circuit Breaker, 115kV 115kV, 1200A 1 each Circuit Breaker, 138kV 138kV, 1200A 1 each Distance and Overcurrent 1 lot Transformer Relaying Transformer and Bus Protection Quartz Creek Substation Power Transformer -138kV-69kV S6MVA Base Rating " Circuit Breaker, 138kV 138kV, 1200A Distance and Overcurrent Transformer Relaying Transformer and Bus Protection Daves Creek Substation Power Transformer -138kV-24.9kV 10MVA Base Rating | teach | Power Transformer -138kV-69kV 10MVA Base Rating Circuit Breaker, 138kV 138kV, 1200A Line Relaying Distance and Overcurrent Transformer Relaying Transformer and Bus Protection | 1tot | PEI-HLY 23-017 (01/23/96) 120293-01/rh il-1 | 2 tot Lawing Substation | Equipment — | CRRatting’ ~—CSC*dCQarnttity'— Power Transformer -138kV-69kV-24.9kV_|20MVA Base Rating [teach | Circuit Switcher, 138kV 138kV, 1200A Distance and Overcurrent | ttot__ [Transformer Relaying Ss Transformer and Bus Protection —s | —s 1 lot__—is Summit Lake Substation [Power Transformer -138kV-?7kV___—([1.25MVABase Rating ss | ~St each | 138kV, 1200A | 3each __| Hope Substation Power Tcanatenier "i 38kV-27kV 2.5MVA Base Rating | teach | 138kV, 1200A Power Trenatoniner? T38KV- 22kV 1.25MVA Base Rating - - Sing le Phase Circuit Switcher, 138kV 138kV, 1200A | _2each | 138kV, 1200A | teach | i i a a oat Tg TT [Transformer and Bus Protection [1 lot__| Rating 2.6MVA Base Rating 138kV, 1200A 138kV, 1200A Quantity 1 each Power Transformer -138kV-??kV Circuit Switcher, 138kV Power Fuses University Substation Requirements Equipment Power Transformer -115kV-138kV Rating 150MVA Base Rating / 200MVA Top Rating [Circuit Breaker, 138kV_——s*138KV, 200A CsCi‘dESCSC. atch Line Relaying [Distance and Overcurrent sd] SA lot__—i Transformer Relaying [Transformer and Bus Protection _—s [1 lot__| Reactive Compensation Requirements None N/A 0 PEI-HLY 23-017 (01/23/96) 120293-01/rh W-2 Alternative 1B - Upgrade Existing 115kV Line With shunt Capacitiors Transmission Line Requirements TEE eqeadgsevnang HAMMEL NTA TAUNTON eet MULTE ONT NOT ' Reconductor Girdwood -Indian Section of |138kV, 900A, 795 Drake ACSR 203kcmil Brahma [ATE OMNI] Underground Transmission Line [ Norve T TUT ALLY) Reactive Compensation Requirements Alternative 1C - Convert Existing Route To 230kV Transmission Line Requirements Reconstruct at 230kV Overhead 230kV, 900A, 795 Drake ACSR Construction Underground Transmission Line Soldotna Substation Requirements Power Transformer -115kV-230kV T50MVA Base Rating / 200MVA Top eisai Rating Circuit Breaker, 115kV 115kV, 1200A Circuit Breaker, 230kV 230kV, 1200A Distance and Overcurrent ini Transformer Relaying Transformer and Bus Protection iin Quartz Creek Substation |Power Transformer -230kV-69kV__—[S6MVA Base Rating | teach | Line Relaying SC Distance and Overcurrent | lot [Transformer Relaying | Transformer and Bus Protection [lot Daves Creek Substation Power Transformer -230kV-24.9kV 10MVA Base Rating |_Quantity _| |__teach_ | Power Transformer -230kV-69kV 10MVA Base Rating | teach | Circuit Breaker, 230kV 230kV, 1200A | _3each_ | i ing Di hiker {AIA Not aT Transformer and Bus Protection Transformer Relaying PEI-HLY 23-017 (01/23/96) 120293-01/rh Il-3 Lawing Substation Power Transformer -230kV-69kV-24.9kV_|20MVA Base Rating Circuit Switcher, 230kV 230kV, 1200A Distance and Overcurrent Transformer and Bus Protection | Equipment Power Transformer -230kV-??kV 1.25MVA Base Rating 230kV, 1200A | _3each | Hope Substation [Equipment | CRatting Quant Power Transformer -230kV-??kV 2.5MVA Base Rating 1 each Power Fuses 230kV, 1200A 3 each Portage Substation Equipment Rating Power Transformer -230kV-??kV 1.25MVA Base Rating - Single Phase Circuit Switcher, 230kV 230kV, 1200A Power Fuses 230kV, 1200A Girdwood Substation Equipment Power Transformer -230kV-24.9kV 11.2MVA Base Rating Circuit Switcher, 230kV 230kV, 1200A Distance and Overcurrent Transformer Relaying Transformer and Bus Protection Indian Substation Equipment [| —C‘éRting’ Ss Power Transformer -230kV-??kV 2.6MVA Base Rating Circuit Switcher, 230kV 230kV, 1200A 230kV, 1200A University Substation Requirements Power Transformer -115kV-230kV 150MVA Base Rating / 200MVA Top Rating Circuit Breaker, 230kV 230kV, 1200A Line Relaying Distance and Overcurrent Transformer Relaying Transformer and Bus Protection Reactive Compensation Requirements Shunt Reactor Aproximately 20Mvar Circuit Switcher 230kV, 1200A Transformer Relaying Transformer and Bus Protection PEI-HLY 23-017 (01/23/96) 120293-01/rh W-4 SUBSTATION 198 KV , SOLDOTNA ( 14.4/24.9 KV } ) GENERATING PLANT ; 9 J 116 KV 69 KV 1 ‘ 230 KV : DOTNA SS LY x EA) 7.2/12.6 KV NOTE: LOCATION FOR ELECTRICAL IS APPROXIMATE ELECTRICAL STUDY P.0. Box 196300 EXISTING ROUTE Anchorage, Alaska 99519-6300 UT PCC 3.2 PARALLEL EXISTING LINE The following major equipment has been identified for the new intertie alternatives that roughly parallel the existing 115kV line. Figure 7 shows the assumed line route, and Figure 8 shows the simple one-line diagram of the alternative. Alternative 2 - Parallel Existing Route, 138kV through Portage Transmission Line Requirements Overhead Transmission Line 138kV, 900A, 795 Drake ACSR | 143 miles | Underground TransmissionLine [None sC~—“‘“(C;CSCO;!;C;COC;C*C*C*#*drNSCON”CO(OOTCdS Soldotna Substation Requirements Power Transformer -115kV-138kV_|150MVA Base Rating / 200MVA Top Rating | teach | Circuit Breaker, 115kV 115kV, 1200A Circuit Breaker, 138kV 138kV, 1200A Line Relaying Distance and Overcurrent Din Transformer Relaying Transformer and Bus Protection iA HOC TIN) University Substation Requirements NT AAA ah TTC ney Circuit Breaker, 138kV 138kV, 1200A | teach | Distance and Overcurrent Iii Transformer Relaying Transformer and Bus Protection HSIN FoR TTL] Reactive Compensation Requirements LOCO ey cago AAA ey ATTA 7 Chest) [/Necorne iii: hint E TY NPAC TTT NA Alternative 2A - Parallel Existing Route, 138kV Crossing at Bird Point Transmission Line Requirements Overhead Transmission Line 138kV, 900A, 795 Drake ACSR Overhead Crossing Cable To Be Determined Crossing Structures To Be Determined f Underground Transmission Line | Neorveo HUE LINTTS SSCA NCAT AAT ALONE T Soldotna Substation Requirements Power Transformer -115kV-138kV__| 150MVA Base Rating / 200MVA Top Rating 1 each Circuit Breaker, 115kV 115kV, 1200A 1 each Circuit Breaker, 138kV 138kV, 1200A 1 each Distance and Overcurrent ing Transformer and Bus Protection Transformer Relaying PEI-HLY 23-017 (01/23/96) 120293-01/rh l-6 University Substation Requirements Circuit Breaker, 138kV 138kV, 1200A Transformer Relaying Transformer and Bus Protection 1 lot Reactive Compensation Requirements Equipment Ratin | Quantity |] ee _— 4 Alternative 2B - Parallel Existing Route, 230kV through Portage Transmission Line Requirements | Equipment | Rating, Quantity | Overhead Transmission Line 230kV, 900A, 795 Drake ACSR | 143 miles | Underground Transmission Line None | oOo | Soldotna Substation Requirements Equipment Rating Power Transformer -115kV-230kV_| 150MVA Base Rating / 200MVA Top Rating 4 each Circuit Breaker, 115kV 115kV, 1200A 1 each teach Line Relaying Transformer Relaying Transformer and Bus Protection University Substation Requirements [| __——Equipment | t—“‘!CCRatin<g’”: «= CSC*C*édL:CQantitly'‘ Circuit Breaker, 230kV 230kV, 1200A | teach | Line Relaying Distance and Overcurrent | 1lot | Reactive Compensation Requirements Equipment Rating | Quantity | Shunt Reactor 22Mvar Circuit Breaker, 230kV 138kV, 1200A Reactor Relaying Transformer and Bus Protection Alternative 2C - Parallel Existing Route, 230kV Crossing at Bird Point Transmission Line Requirements Overhead Transmission Line 230kV, 900A, 795 Drake ACSR Overhead Crossing Cable To Be Determined To Be Determined Underground Transmission Line [None SSCS PEI-HLY 23-017 (01/23/96) 120293-01/rh Ill -7 Soldotna Substation Requirements 150MVA Base Rating / 200MVA Top Rating [Circuit Breaker, 115kV_—s*[115KV, 1200A_ es C“it‘“‘;S™C‘*dr:C#S. atch [Line Relaying —s—s—sSSCSC*C*d(@DStancce@ and Overrcuent_ Tt tot Transformer and Bus Protection University Substation Requirements [———SsEquipment | t—C“‘SCCRating’” «= C~‘“‘*C‘*d:«CQuuaaznt'itly'*C Circuit Breaker, 230kV 230KV, 1200A |_1each | Line Relaying Distance and Overcurrent Transformer Relaying Transformer and Bus Protection Reactive Compensation Requirements Shunt Reactor To Be Determined 2 each Circuit Breaker, 230kV 230kV, 1200A [teach | Reactor Relaying Transformer and Bus Protection | _1lot | PEI-HLY 23-017 (01/23/96) 120293-01/rh l-8 BUS 11015 R=0.01535 PU ALT 2A-25 Mi 795 DRAKE X"0.09967 PU B=0.02669 PU R=0.0307 PU ALT2-SOMI 795DRAKE —X=0.19934 PU B=0.05338 PU BUS 11014 BUS 11013 R=0.00387 PU X=0.02513 PU B=0.00672 PU 6.3 Mi 795 DRAKE BUS 11012 BUS 11011 116-138KV 1650MVA IN PARALLEL SOLDOTNA 115KV BUS Figure 7: PARALLEL EXISTING ROUTE W/ 138 KV * impedances are per unit on 138kV, 100MVA base. Wl-9 SOLDOTNA 115KV BUS * impedances are per unit on 230kV, 100MVA base. BUS 21015 R=0.00374 PU X=0.02515 PU B=0.04844 PU BUS 21013 BUS 21012 BUS 21011 Figure 8: PARALLEL EXISTING ROUTE W/ 230 KV Ill- 10 ; | g a BY JF < I ¢ q a 4 > CAV $ SM ¥ SEH) |g Z iu r FIGURE 9 ELECTRICAL STUDY PARALLEL ROUTE Pt. Possession ATO WUT AL AUT i g ; |S tA 7d |Aa eal [HEED zz 3 eee ESeczedar 3” (fu & : ee i 3.3 ENSTAR ROUTE The following major equipment has been identified for the new intertie Enstar alternatives that roughly parallel the Enstar pipeline from Soldotna Substation to International Substation. Figures 10 and 11 show the simple one-line diagram of the 138kV and 230kV alternative configurations. Figure 12 shows the assumed line route. Alternative 3 - Enstar Route at 138kV Transmission Line Requirements [Overhead Transmission Line | 138kV, 900A, 795 Drake ACSR___ | 60.2 miles | [Submarine Transmission Line___[138kV, 1000kcmil, copper, SCFF_ | 8.5 miles _| [Underground Transmission Line __[138kV, 1000kcmil, copper, SCFF__— | 4.25 miles | Soldotna Substation Requirements Power Transformer -115kV-138kV 150MVA Base Rating / 200MVA Top Rating Circuit Breaker, 115kV 115kV, 1200A Circuit Breaker, 138kV 138kV, 1200A Line Relaying Distance and Overcurrent | tot | | itot__| Transformer Relaying Transformer and Bus Protection University Substation Requirements Circuit Breaker, 138kV 138kV, 1200A Distance and Overcurrent | itot | Transformer Relaying Transformer and Bus Protection | 1lot | Cable Termination Stations - Both Stations Transfer - Disconnect Switch with bus |138kV, 1200A Cable Terminations 138kV Reactive Compensation Requirements [Transformer Relaying | Transformer and Bus Protection | 2 lot PEI-HLY 23-017 (01/23/96) 120293-01/rh I-12 Alternative 3A- Enstar Route at 230kV Transmission Line Requirements 230kV, 1000kcmil, copper, SCFF |_ 8.5 miles _| [Underground Transmission Line___[230kV, 1000kcmil, copper, SCFF_— | 4.25 miles | Soldotna Substation Requirements |Power Transformer -115kV-230kV__|150MVA Base Rating / 200MVA Top Rating _| teach __| [Circuit Breaker, 230kV_—(230KV,1200A_ Tt each | [LineRelaying Ss C*dDistance and Overcurrent | ot [Transformer Relaying Ss Transformerand Bus Protection | lot University Substation Requirements Equipment Rating Circuit Breaker, 230kV 230kV, 1200A Distance and Overcurrent Transformer Relaying Transformer and Bus Protection Cable Termination Stations - Both Stations Reactive Compensation Requirements TE = TT i Shunt Reactor 230kV, 60Mvar 2 Circuit Switcher 30KV, 1200A Transformer Relaying Transformer and Bus Protection PEI-HLY 23-017 (01/23/96) 120293-01/rh I-13 R=0.00013 PU X=0.00017 PU B=0.01071 PU R=0.00205 PU X=0.00386 PU B=0.17140 PU BUS 11023 R=0.0195 PU X=0.1310 PU B=0.03224 PU BUS 11021 115-138KV fro. coses pu 150 MVA SOLDOTNA 115KV Bus Figure 10: ENSTAR ROUTE 138 KV * impedances are per unit on 138kV, 100MVA base. INTERNATIONAL BUS 9984 138KV BUS 138-230KV 160 MVA 230kV BUS BUS 21029 LINK 2.8 8.6 MI 795 DRAKE BUS 21028 REACTOR LINK 1.9 MI 795 DRAKE 60 MVAR zs BUS 21026 | LINK 2.5 | 0.25 Mi 1000KCMIL. Z30kV SCFF | Pepucanlcen cal BUS 21025 | | 8.5 MI 1000KCMIL LINK 2.4 | sore | | —t+——__ Bus 21024 ! LINK 2.3 | 4.0 Mi 1000 KCMIL | 230KV SCFF | | BUS 21023 REACTOR 60 MVAR LINK 2.2 31.6 MI_795 DRAKE BUS 21022 LINK 2.1 18.1 Mi 795 DRAKE 230kV BUS BUS 21021 115-230KV 150 MVA SOLDOTNA 115KV Bus BUS 9989 “impedances are per unit on 230kV, 100MVA base. Figure 11: ENSTAR ROUTE 230 KV W-15— R=0.00064 PU X=0.02666 PU R=0.00190 PU X0.01242 PU B=0.02532 PU R=0.00042 PU X=0.00274 PU B=0.00559 PU R=0.00005 PU X=0.00007 PU B=0.02116 PU R=0,00158 PU X=0.00225 PU B=0.71944 PU R=0.00074 PU X=0.00106 PU B=0.33856 PU R=0.00698 PU X=0.04701 PU B=0.09060 PU R=0.00400 PU X=0.02694 PU B=0.05188 PU R=0.00079 PU X=0.03332 PU e \ i a 5 iS aD Dy \ t 4, (LZ GSK % Gi = SS 2, a> 4 AW x \ ) Sy ey BS rm 4 \ FIGURE 12 ELECTRICAL STUDY ENSTAR ROUTE $601 Minnesota Drive P.O. Box 196300 Anchorage, Alaska 99519-6300 Pt. Woronzor’ _ — Ae f «(IIT 14.4/24.9 KV 7.2/12.5 KV SUBSTATION GENERATING PLANT 16 KV 230 KV 188 KV 69 KV NOTE LOCATION FOR ELECTRICAL IS APPROXIMATE 3.4 TESORO ROUTE The following major equipment has been identified for the new intertie alternatives that roughly parallel the Tesoro pipeline from Bernice Lake Power Plant to Point Woronzof. Figures 13 and 14 show the simple one-line diagram of the 138kV and 230kV alternative configurations. Figure 15 shows the assumed line route. Alternative 4 - Tesoro Route at 138kV Transmission Line Requirements 138kV, 900A, 795 Drake ACSR Submarine Transmission Line 138kV, 1000kcmil, copper, SCFF | 15.9 miles | [Underground Transmission Line __[138kV, 1000kcmil, copper, Solid Dielectric __|__4 miles _| Note: The preliminary routing survey has indicated that a 4 mile line section through Captain Cook State Park will probably need to be underground construction. This is not indicated on the one-line diagrams or included in the load flows models. Bernice Power Lake Plant Substation Requirements Equipment Rating | Quantity | | teach __| Power Transformer -115kV-138kV 150MVA Base Rating / 200MVA Top Rating Circuit Breaker, 115kV 115kV, 1200A | teach | Circuit Breaker, 138kV 138kV, 1200A [teach | Line Relaying Distance and Overcurrent i ae Transformer Relaying Transformer and Bus Protection PIN A est i Point Woronzof Substation Requirements Equipment Rating | Quantity | Transfer - Disconnect Switch with bus |138kV, 1200A Cable Terminations 138kV | 4each | Note: This equipment assumes a new terminal for the cable. The existing cable terminations for the failed Point Mackenzie - Point Woronzof cable may be reused. Cable Termination Station - Possession Point Sn TESTE FT atone heey | Transfer - Disconnect Switch with bus |138kV, 1200A Cable Terminations 138kV | 4each | Wlw Reactive Compensation Requirements SOOT TTT eng TUTTO TT Shunt Reactor Shunt Reactor 1 each Transformer Relaying Note: This equipment listing assumes that the existing reactors at Point Woronzof can be used to counteract the cable capacitance on that end. PEI-HLY 23-017 (01/23/96) 120293-01/rh Il -17 Alternative 4A- Tesoro Route at 230kV Transmission Line Requirements rate a ie Overhead Transmission Line 230kV, 900A, 795 Drake ACSR 39.6 miles [Submarine Transmission Line____—‘||230kV, 1000kcmil, copper, SCFF__— | 15.9 miles | [Underground Transmission Line__|230kV, 1000kcmil, copper, Solid Dielectric __|_4 miles _| Note: The preliminary routing survey has indicated that a 4 mile line section through Captain Cook State Park will probably need to be underground construction. This is not indicated on the one-line diagrams or included in the load flows models. Bernice Lake Power Plant Substation Requirements [Equipment | SC C“‘:OCRatting’” ~—CSCSCSCSC*d;sSsQuantity | Power Transformer -115kV-230kV 150MVA Base Rating / 200MVA Top Rating 1 each Circuit Breaker, 115kV 115kV, 1200A 1 each Circuit Breaker, 230kV 230kV, 1200A 1 each Line Relaying Distance and Overcurrent [Equipment] [Circuit Breaker, 230kV_ ss C«d23OKV, 200A Cs teach [Circuit Breaker, 138kV_ ss C«138KV,1200A es C“‘CNCOOC*NS Cah CY Distance and Overcurrent [2 tot__| Transformer and Bus Protection 1 lot Cable Termination Stations - Both Stations [Equipment Transfer - Disconnect Switch with bus |230kV, 1200A Cable Terminations 230kV 230kV, 30Mvar Reactive Compensation Requirements 1 each Shunt Reactor [Shunt Reactor 230KV, 40Mvar CT teach | [Circuit Switcher 230KV, 200A Cd Seach [Transformer Relaying ss Transformer and Bus Protection ss |_ 3 lot PEI-HLY 23-017 (01/23/96) 120293-01/rh I-18 11 MVAR 20 MVAR 11 MVAR BUS 11310 R=0.00113 PU X=0.00147 PU B=0.08301 PU ——T——__ BUS 11039 LINK 3.4 13.65 MI 1000KCMIL 138KV SCFF R=0.01519 PU X=0.09868 PU B=0.02643 PU BUS 11033 16.5 MI 795 DRAKE BUS 11032 115-138KV 150 MVA BERNICE 115KV BUS BUS 9990 EXISTING 115KV LINE SOLDOTNA 115KV BUS Figure 13: TESORO ROUTE 138 KV S$ are per unit on 138kV, 100MVA base. -19 BUS 21311 2.4 Mi 795 DRAKE BUS 21310 2.2 Mi 1000KCMIL BUS 21033 BUS 21032 115-230KV 150 MVA EXISTING 115KV LINE Figure 14: TESORO ROUTE 230 KV * impedances are unit on 230kV, 100MVA base. per SOLDOTNA 115KV BUS Il - 20 = “/ PN BY // UF JQ Be Zr Sn) i WY GSS FIGURE 15 ELECTRICAL SYUDY TESORO ROUTE Bn UU AY ibs (AEGXT) < = - 2 9° ” . SOLDOTNA ( «|| II 14.4/24.9 KV SUBSTATION GENERATING PLANT 16 KV 230 KV 188 KV 7.2/12.6 KV 69 KV NOTE LOCATION FOR ELECTRICAL IS APPROXIMATE 3.5 BELUGA ROUTE The following major equipment has been identified for the new intertie alternatives from Bernice Lake Power Plant to Beluga Power Plant. Figures 16 and 17 show the simple one-line diagram of the 138kV and 230kV alternative configurations. Figure 18 shows the assumed line route. Alternative 5 - Beluga Route at 138kV Transmission Line Requirements [Submarine Transmission Line___|138kV, 1000kcmil, copper, SCFF__— | 21.0 miles | [Underground Transmission Line___|138kV, 1000kcmil, copper, Solid Dielectric _| _4 miles _| Note: The preliminary routing survey has indicated that a 4 mile line section through Captain Cook State Park will probably need to be underground construction. This is not indicated on the one-line diagrams or included in the load flows models. Bemice Lake Power Plant Substation Requirements [—Ss—CEquipment_ sd Rating | Quantity | Power Transformer -115kV-138kV __|150MVA Base Rating / 200MVA Top Rating | 1each | Circuit Breaker, 115kV 115kV, 1200A Circuit Breaker, 138kV [138kV,1200A,— — C—“‘“SNCC(C*NS OC ach si Line Relaying [Distance and Overcurrent Cid; lot Transformer Relaying [Transformer and Bus Protection ss] St loti Beluga Power Plant Substation Requirements Equipment ing | Quantity | [LineRelaying «Distance and Overcurrent Cd] tt [Transformer Relaying | Transformerand Bus Protection ss] i lot__ Cable Termination Station - Both Terminals Equipment Rating Quanti Transfer - Disconnect Switch with bus | 138kV, 1200A | 16 each Cable Terminations 138kV 8 each Reactive Compensation Requirements [Shunt Reactor SSSS~«*dSORW,4OMver——SSSSSSSSS*dCSt rch] [cirouit Switcher |138kV, 1200A | ~3 each] [Transformer Relaying | Transformer and Bus Protection | 3 ot PEI-HLY 23-017 (01/23/96) 120293-01/rh I-22 Alternative 5A- Beluga Route at 230kV Transmission Line Requirements [Submarine Transmission Line | 230kV, 1000kcmil, copper, SCFF | 21.0 miles | [Underground Transmission Line [230kV, 1000kcmil, copper, Solid Dielectric __[_4 miles _| Note: The preliminary routing survey has indicated that a 4 mile line section through Captain Cook State Park will probably need to be underground construction. This is not indicated on the one-line diagrams or included in the load flows models. Bemice Lake Power Plant Substation Requirements 150MVA Base Rating / 200MVA Top Rating [Circuit Breaker, 115kV__ ss *'115kV,1200ACC“‘CSCS*CL:SCOC atch [Line Relaying —SSC*d Distance and Overcurrent C*d;:C2 Mot Cid [Transformer Relaying _—s—SCSSC*d Trransformerand Bus Protection —Ss—s | = lots Beluga Power Plant Substation Requirements . Rating Circuit Breaker, 230kV 230kV, 1200A Line Relaying Distance and Overcurrent Bus Relaying Bus Protection Cable Termination Station - Both Terminals Equipment Rating Quanti Transfer - Disconnect Switch with bus | 230kV, 1200A 16 each Cable Terminations 230kV 8 each Reactive Compensation Requirements [Equipments Rating Quanti Shunt Reactor 230kV, 90Mvar 2 each Circuit Switcher 230kV, 1200A 2 each Transformer Relaying Transformer and Bus Protection 2 lot PEI-HLY 23-017 (01/23/96) 120293-01/rh I-23 BERNICE 115KV BUS EXISTING 115KV LINE SOLDOTNA 115KV BUS Figure 16: BELUGA ROUTE 138 KV * impedances are per unit on 138kV, 100MVA base. BUS 9970 14.0 Mi 795 DRAKE BERNICE 115KV BUS EXISTING 115KV LINE SOLDOTNA 116KV BUS Figure 17: BELUGA ROUTE 230 KV * impedances are per unit on 230kV, 100MVA base. Wl - 25 > x é z = x i nt SUBSTATION 15 KV 69 KV 230 KV 188 KV GENERATING PLANT NOTE LOCATION FOR ELECTRICAL IS APPROXIMATE (9/ emeen /estmaonge ony FIGURE 18 ELECTRICAL STUDY BELUGA ROUTE TTT UU Pu | ci PEUIT b+ Ig \o— i] i ROUTE SELECTION 3.6 BATTERY ENERGY STORAGE SYSTEMS The following major equipment alternative. has been identified for the Battery Energy Storage Alternative 6 - Battery Energy Storage Transmission Line Requirements Gaarfadaiad Saeco Raced [Equipment Bernice Lake Power Plant Substation Requirements [Equipment] 40MW, 20 minutes 1 each 138kV, 1200A 1 each Transformer and Bus Protection 1 lot 40MVA Base Rating 1 each Reactive Compensation Requirements PEI-HLY 23-017 (01/23/96) 120293-01/rh Ill - 27 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 ; fb t 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 : : f I R li bili ine f I cilitenise 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 ....... EEE Le A ALA RUA Page 2 NERC Terms and Definitions ........... ee Page 17 Recommended by Reliability Criteria Subcommittee:. February 19, 1991 Adopted by the Alaska Systems Coordinating Council: April 4, 1991 MMB en te | eg a es ee 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 reconfiguration of the bulk power transmission system to facilitate system restoration. ° Protective relaying equipment is provided to minimize the severity and extent of system disturbances and to allow for malfunctions in the protective relay system without undue risk to system reliability. ° Black start-up capability is provided for individual systems. ° 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 #2 xxx Criteria #3 Criteria #40 xxx Criteria #50 *#x* Criteria #6 Criteria #7 Criteria #8 Criteria #9 Criteria #10 Criteria #11 Criteria #12 aa —_— 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: 1 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. 1.3. 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. . 15. Loss of any substation bus section. Multiple Contingency: Tequires the operation of the back up relay scheme to remove the faulted section of line. Recommendations approved 1. All facilities should remain below their emergency rating folowing any Singlesar mmxinipia 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 Na 4.1. Voltage Level: Minimum Maximum First Power Swing: 0.80 pu V 1.10 pu V (for 0.5 sec.) Intermediate: 0.92 pu V | LOS pu V (for 2 minutes) Steady State: 0.95 pu V 1.05 pu V 42. Frequency: ” 58.8 Hz j 615 Hz Load-shedding should be planned for adequate system response to multiple contingencies to avoid system collapse. (Remainder of page intentionally blank) ASCC Planning Criteria #2, Page 2 of 2 . , 5 = mor 4 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 voltage stability analyses to ensure sarees with all Planning Reliability Criteria. Recommendations 1, Transmission ties should be designed to carry emergency transfers following any single contingency on the interconnected system. 7 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, Pagelof1l 7 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 Sizing and location of static Var systems shall be such that any ‘Single contingency shall not result in the loss of the static Var imran a All reactive resource equipment shall be expats of continuous operation during system frequency excursions resulting from credible contingencies. Reactive resources shall be sized and provided with controls sufficient to start, operate, and stop them without causing undue adverse system effects. Recommendations i 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. 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. ; 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. 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. 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, Page 1 of 1 * 8 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: See BUS eon X AREA V(PU) V(KV) eee 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) Re 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 2G13.8 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 3966 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: X=ace=— 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 1.0938 13.672 998 SOLD SVS9.36 11.0539 9.865 BUSES WITH VOLTAGE LESS THAN 0.9500: ee BUS ----- X AREA V(PU) V(KV) Kea 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 2G13.8 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: a BUS) ea X AREA V(PU) V(KV) 2 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: ee BUS ----- X AREA V(PU) V(KV) eee 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 3G13.8 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. WAINI2.5 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 QRTZ 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: Xo----- BUS ----- X AREA V(PU) V(KV) Ke 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: z X------ SUS. X AREA V(PU) V(KV) a 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 2° DOWER ORIGINAL MGINEERS 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 | 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, eee 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 - 19 -01 RWR y ce: 120293-01 ef Ne Larry Henriksen Frank Rowland Miek-Gross sermpseicGrew «Jack Hand §=D&L: Del LaRue PEI-HLY 55-0049 D&M: Garlyn Bergdale-AZ / Tim Tetherow-CO / Niklas Ranta-AK 3940 Glenbrook Drive » PO. Box 1066 + Hailev Idaho 83332 « /9NR) 7RA.2AGA . Fay: 19N0\ FAM AAAR nN ss POWER Engineers, Inc. yor 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 RW/Ref PEI-HLY 22-029 2