Peru-Chile Interconnector: Technical Analysis Study

Transcription

1 Technical Support to Peru/Chile Peru-Chile Interconnector: Technical Analysis Study Prepared for: Prepared by: Office of Energy Programs Deloitte Financial Advisory Services, LLP Bureau of Energy Resources 1919 N. Lynn Street U.S. Department of State Arlington, VA Black & Veatch Lamar Ave. Overland Park, KS June 25, 2015 This work was funded by the U.S. Department of State, Bureau of Energy Resources, Power Sector Program This work does not necessarily reflect the views of the United States Government.

2 DISCLAIMER This document has been prepared by Deloitte Financial Advisory Services LLP ( Deloitte FAS ) and Black and Veatch Special Projects Corporation (Black & Veatch) for the U.S. Department of State ( DoS ) under a contract between Deloitte FAS and DoS. This document does not necessarily reflect the views of the Department of State or the United States Government. Information provided by DoS and third parties may have been used in the preparation of this document but was not independently verified by Deloitte FAS. The document may be provided to third parties for informational purposes only and shall not be relied upon by third parties as a specific professional advice or recommendation. Neither Deloitte FAS nor its affiliates or related entities shall be responsible for any loss whatsoever sustained by any party who relies on any information included in this document. Page ii

3 TABLE OF CONTENTS 1. EXECUTIVE SUMMARY INTRODUCTION BACKGROUND STUDY OBJECTIVE PERUVIAN POWER SYSTEM CHILEAN POWER SYSTEM PROPOSED PERU CHILE INTERCONNECTION LOCATION STUDY APPROACH AND SCENARIOS SYSTEM ANALYSIS STEADY STATE POWER FLOW ANALYSIS FAULT ANALYSIS TRANSIENT STABILITY ANALYSIS HIGH VOLTAGE DC (HVDC) TECHNOLOGIES HISTORY OF HVDC SYSTEMS HVDC PROCESS HVDC APPLICATIONS BACK-TO-BACK HVDC CONVERTERS LINE COMMUTATED CONVERTERS (LCC) / CURRENT SOURCE CONVERTERS (CSC) VOLTAGE SOURCE CONVERTERS (VSC) / FORCED COMMUTATED CONVERTERS COMPARISON OF TECHNOLOGIES SHORT CIRCUIT RATIO (SCR) CONCEPTUAL INTERCONNECTOR PROJECT ARRANGEMENT ESTIMATED COST FOR THE INTERCONNECTOR MW INTERCONNECTION CONCLUSIONS ANNEX 1 POWER FLOW ONE LINE DIAGRAMS NEW GENERATORS MODELED IN SOUTHERN PERU INTERCONNECTOR MODEL ANNEX 2 SAMPLE TRANSIENT STABILITY PLOTS MW INTERCONNECTOR Page iii

4 Acronyms AC BPA DC DoS ESCR ENR EPC GTO HVDC Hz IGBT IMF km kv LCC MoF MVA MVAR MW PWM SEIN SCR SIC SINEA Alternating Current Blanket Purchase Agreement Direct Current Department of State Effective Short Circuit Ratios Bureau of Energy Resources Engineering, Procurement and Construction Gate Turn Off High Voltage Direct Current Hertz Insulated Gate Bi-polar Transistors International Monetary Fund Kilometers Kilovolt Line Commutated Converters Ministry of Finance Mega volt amperes Mega volt amperes reactive Mega-watt Pulse Width Modulation Sistema Interconectado Nacional (Peru s Electricity System) Short Circuit Ratio Sistema Interconectado Central (Chile s Central Electricity System) Andean Electrical Interconnection System Sistema Interconectado del North Grande (Chile s Northern Electricity System) Page iv

5 SING SOW SVC TO UG VSC Scope of Work Static VAR Compensators Task Order Underground Voltage Source Converter Page v

6 1. EXECUTIVE SUMMARY Power exchange between Peru and Chile has long been a topic of discussion in the region but, thus far, has remained at the theoretical level and the power systems of these two countries have not been physically interconnected. This interconnection could be the initial step to developing trading arrangements between the two countries, yielding benefits, such as reduction in prices, promotion of investment, increase in reliability and diversification of supply. Peru s System Economic Operation Committee (COES), Chile s Northern Electricity System (CDEC-SING), and the Department of State, Bureau of Energy Resources, Power Sector Program (hereafter, Department of State or DoS) designed this task to analyze the economic and technical feasibility of connecting Peru and Chile s electrical systems. The idea originated as a request from COES and CDEC-SING for technical assistance to develop technical and economic analysis, as well as to prepare a set of specifications and models that will help the Chilean and Peruvian system operators begin the interconnection process, should the appropriate economic and technical conditions be met. This Technical Study assesses the technical feasibility of such interconnection, evaluates the production costs, and discusses a least cost alternative for a transmission line connecting the two countries. A companion Planning Analysis, also prepared as part of this activity, evaluates the economic benefit of these power exchanges. The Peruvian Chilean power transfer studied herein involves a potential interconnection between Tacna, Peru and Arica, Chile. Two alternatives have been considered: (1) using two 220-kV AC lines that are linked into a HVDC converter station with back to back DC converters that allow for the transfer of power between the 60 Hz (SEIN-Peru) and 50 Hz (SING-Chile) systems and (2) using a high voltage DC transmission line between Tacna and Arica. The combined length of the 220-kV lines is approximately 54 km. This interconnection is assessed at three different converter station sizes/ratings (100 MW, 150 MW, and 200 MW). System studies were performed for all three ratings. Steady state power flow studies have indicated a higher reactive power requirement at the Los Heroes substation in Tacna, Peru for the 200 MW interconnection option as compared to the other two ratings. Table 1-1 indicates the constraints that were identified from the system studies along with the corresponding potential mitigation action to operationalize the interconnection project. There were no issues identified on the SING system with regards to capacity analysis; however the implementation of the second 220 kv line from Condores to Parinacota will be very important for the Peruvian Chilean interconnection. If this second line is not in place in Northern Chile for the Peruvian Chilean interconnection project, then it will pose an additional constraint on the Northern Chilean system. Interconnection Level Table 1-1: Identified System Constraints Contingency Impact Mitigation 100 MW, 150 MW and 200 MW Montalvo 500/230 kv transformer System instability Peru has plans to install a second transformer in Until such time, the HVDC converter shall be tripped for the loss of Montalvo 500 kv transformer. Page 1

7 Interconnection Level Contingency Impact Mitigation 150 MW and 200 MW Montalvo Los Heroes 220 kv line The other Montalvo Los Heroes 220 kv line overloads DC power needs to be ramped down. Based on the calculated fault levels, there is enough Short Circuit Ratio (SCR) available at Los Heroes (Tacna) and Parinacota (Arica) substations for 100 and 150 MW ratings, which means that the HVDC scheme using thyristor can be applied without any additional dynamic reactive power devices. Short Circuit Ratio at Parinacota is very low for a 200 MW converter rating and, as such, it will require a synchronous condenser of about 30 MVA rating to provide the required AC system strength. Initial transient stability studies did not indicate any voltage recovery or stability issues following major disturbances. These stability studies, however, should be performed again during the design stage of the interconnection project using more accurate and realistic converter control models provided by the selected HVDC equipment suppliers. Back-to-Back HVDC converter or two HVDC converters connected through an HVDC line are the two possible options for the Peru Chile interconnection. The estimated budgetary cost for all three ratings is shown in Table 1-2. Table 1-2: Budgetary Cost for the Interconnection with Back-to-Back HVDC Converter Station Interconnector Rating Estimated Project Cost for Back-to-Back Converters Option Estimated Project Cost for HVDC Line Option 100 MW US $82.5 million US $91.6 million 150 MW US $100.4 million US $112.4 million 200 MW US $131.5 million US $145.7 million A second interconnection between Peru and Chile was studied as a sensitivity case and was assumed to be in service by This interconnection was considered as a 1000 MW, +/-500 kv, 607 km HVDC transmission line between Montalvo in Peru and Crucero in Chile. The steady state studies have indicated that it would be feasible to operate both the 200 MW Back-to-Back and the 1000 MW HVDC interconnector together. Detailed transient stability studies will have to be performed during the design phase and identify the controllers that will be required for proper operation. System analysis has indicated that the proposed 500 kv transmission line from Crucero to Mejillones in Chile and also the SING-SIC interconnection would be essential for supporting the 1000 MW interconnector; otherwise the HVDC power will have to be ramped down during N-1 contingencies. The studies also indicated that some generation and load tripping will be required on both Peru and Chilean systems whenever the 1000 MW HVDC interconnection is tripped due to faults. The estimated project cost for the 1000 MW interconnection is US $989 million. Page 2

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9 2. INTRODUCTION COES, CDEC-SING, and the Department of State, designed this task to analyze the economic and technical feasibility of building an interconnection between the Peruvian electric system (SEIN) and Chile s northern system (SING) to allow for trading of electric power between the two countries. This task includes a series of economic and technical studies that analyze the interconnection feasibility and prepare a set of models and collection of specifications that will help the Chilean and Peruvian system operators begin the interconnection process, should the appropriate economic and technical conditions be met. In order to carry out these tasks, Deloitte subcontracted Black & Veatch Special Projects Corp (hereafter, Black & Veatch) to carry out a Planning Analysis (the subject of the companion report), a Technical Analysis (subject of this report), an Economic Evaluation (a chapter in the Planning Analysis) and a Preliminary Project Design (the subject of the companion report). In accordance with the Scope of Work provided by the Department of State and as described in our technical proposal, this Technical Analysis study addresses the results from an electrical system analysis of each proposed interconnection alternative; utilizes the results from the production cost simulations to determine total operating costs and the interchange of power between both systems; and discusses the technical definition of the least-cost alternative at the planning level. 3. BACKGROUND Power exchange between Peru and Chile has long been a topic of discussion in the region but, thus far, has remained at the theoretical level and the power systems of these two countries have not been physically interconnected. This interconnection could be the initial step to developing trading arrangements between the two countries, yielding benefits, such as reduction in prices, promotion of investment, increase in reliability and diversification of supply. Additionally, the interconnection of the two systems would be an important part of a broader plan for a multi-country interconnection in Latin America. This concept has the potential to gain traction as Andean countries recommit to regional integration through the newly expanded Pacific Alliance, the Connecting the Americas 2022 Initiative, and the Inter-American Development Bank s Sistema de Interconexion Electrica Andina. In this context, this Technical Analysis study provides an electrical system analysis to assess the technical feasibility of an interconnection between Peru and Chile. 4. STUDY OBJECTIVE The objective of the overall study is to assess the various technical interconnection options and analyze the potential cost and economic benefits of the interconnection between Peru and Chile. A companion Planning Analysis study developed under this contract entitled The Peru-Chile Interconnector: Planning Analysis Study Report provides the details of the economic analysis, whereas this report provides the details of the technical analysis. Core Objectives: Evaluate the alternatives for interconnection; Page 4

10 Perform system analysis and assess project feasibility; Provide the technical definition of project equipment for the least cost alternative based on the economic analysis; and Provide basic layout arrangements. The interconnection is evaluated at three different sizes (100 MW, 150 MW, and 200 MW) that would allow the transfer of power between Chile s Sistema Interconectado del North Grande (SING) and Peru s national grid, Sistema Interconectado Nacional (SEIN). A second interconnection project, with a capacity of 1000 MW, is evaluated as a sensitivity case. In order to model the technical characteristics, this Technical Analysis study utilized DigSilent Power Factory a power system modeling, analysis, and simulation software used by system operators throughout Latin America and, more importantly, by both Peru and Chile. 5. PERUVIAN POWER SYSTEM SEIN is the integrated transmission network of Peru and serves approximately 85 percent of the country s population. Power is distributed through an extensive network of high voltage transmission lines and substations that link the nation s power generation facilities with the distribution network. The high voltage transmission network in Peru, as of 2014, is shown in Figure 5-1. It consists of about 14,442 km of 220 kv and 1,805 km of 500 kv transmission lines 1. The peak demand in 2014 was 5,677 MW, approximately 1.8% higher than the previous year. The SEIN system has expanded in recent years with the benefit of providing power supplies to an increasing percentage of the population, of improving the reliability of the transmission network, and of interconnecting new generation facilities. National plans show continued future expansion of the high voltage transmission network in Peru, including to areas in southern Peru where several mining loads will be interconnected in the medium term and new natural gas fired generation is planned for the long-term. 1 Vision de la Interconecxion Electrica Peru-Chile a Partir de los Pryoyectos del Estudio del SINEA, 14 July 2014: Eduardo Antunez de Mayolo R. Page 5

11 Figure 5-1: SEIN Transmission System as of 2014 The SEIN transmission system is geographically divided into three regions, i.e., North (from Chimbote to the northern end), Center (from Paramonga to Mantaro and Marcona) and South (from Cotaruse to the southern end). The total peak demand is projected to reach 12,322 MW by 2018 and approximately 23% of this demand is expected to be in the South region as shown in Figure 5-2. Page 6

12 Figure 5-2: SEIN s Expected Demand by 2018 The installation of several 500 kv and 220 kv transmission lines are proposed through 2020 (Figure 5-3). These transmission additions are very important for the interconnection with Chile as they provide additional system strength, as well as transmission paths for future power transfer from Ecuador. Page 7

13 6. CHILEAN POWER SYSTEM Figure 5-3: SEIN Transmission System by 2018 The Chilean power system consists of four separate electric grids: Sistema Interconectado del Norte Grande (SING) which serves the desert mining regions in the north, Sistema Interconectado Central (SIC) which serves the central part of Chile, Aysén and Magallanes which serve small areas of the southern part of the country. SING and SIC systems serve about 23% and 76% of the country s total demand, respectively. The SING system mainly consists of Page 8

14 thermal generation, while the SIC system has a mix of thermal and hydro. The SING and SIC systems are currently not electrically interconnected with each other. SING is the integrated transmission network serving northern Chile. The network serves a relatively sparsely populated area but the region has several large load centers that are comprised primarily of mining operations. Consequently, the region is very important economically for Chile and is the source of much of the nation s production of copper, gold, iron, and silver. This dominance of the SING power sector by the energy intensive mining sector is projected to continue. The existing high voltage transmission system in SING is shown in Figure 6-1. It mainly consists of 220 kv and 110 kv transmission lines, with one 345 kv line extending to Argentina. Figure 6-1: SING Transmission System Page 9

15 SIC is the largest integrated transmission network in Chile, serving the central part of the nation including Santiago, the nation s capital and the largest load center. The SIC network serves a large geographic area and, in contrast with the SING system, serves a diverse group of endusers. The SIC system is well developed and has undergone expansion in recent years to increase the interconnected service area and to provide increased reliability. National transmission planning studies show a continued expansion of the high voltage SIC transmission network in the future. Figure 6-2 illustrates the SIC transmission system in detail. Figure 6-2: SIC Transmission System Page 10

16 The SING and SIC systems are proposed to be interconnected with a 600 km, 1500 MVA, 500 kv AC transmission line and this interconnection is expected to be in service by The interconnection will be from Mejillones to Cardones substations. The proposed interconnection is shown in Figure 6-3. Figure 6-3: SING SIC Interconnection 7. PROPOSED PERU CHILE INTERCONNECTION LOCATION Gas pipelines from Camisea gas fields are expected to be available in the Ilo and Tacna regions of Southern Peru by New gas fired power generation is expected to be made available to utilize these gas pipe lines. Figure 7-1 shows the approximate location of the new generators in Southern Peru. Figure 7-1: New Generators Location in Southern Peru The Peru Chile interconnection will utilize a portion of the new gas generators production for export to Chile. Los Heroes 220 kv substation in Tacna, Peru is the closest major substation near to the Chilean border. Montalvo 500 kv / 220 kv substation is the major substation in Page 11

17 southern Peru to which the new generators will be connected. Currently there is one 220 kv circuit between Montalvo and Los Heroes, and there will be one more 220 kv circuit built by The Los Heroes 220 kv substation will be the interconnecting substation in Peru. The proposed Peru Chile interconnection will connect with the northern part of the Chilean power system, i.e., with the SING system. Parinacota 220 kv, in the province of Arica, is the closest major substation near the Peruvian border as shown in Figure 7-2. Currently there is no major generation facility available in the Arica area, except for some photovoltaic solar generation and back up diesel generation. A Parinacota Condores 220 kv circuit serves as a trunk line to this area and a 110 kv transmission line as backup. A second 220 kv transmission line, Condores Pozo Almonte Parinacota, is expected to be in service by This second 220 kv transmission line is vital for the Peru Chile interconnection. The Parinacota 220 kv substation will be the interconnecting substation on the Chilean side. Figure 7-2: SING Transmission System The Peruvian power system uses 60 Hz, whereas the Chilean power system uses 50 Hz. Two AC systems with two different frequencies cannot be interconnected with an AC line, unless there is a frequency conversion in the middle. This can be accomplished with an AC-DC-AC conversion. The following interconnection alternatives have been considered in this study: Page 12

18 1. A back-to-back High Voltage DC (HVDC) converter station near the border, with an approximately 33 km, 220 kv AC line connected to Los Heroes and an approximate 22 km, 220 kv AC line connected to Parinacota; and 2. HVDC converter stations at Los Heroes (Peru) and Parinacota (Chile) connected with an approximately 55 km High Voltage DC (HVDC) line. The conceptual arrangement of the two alternatives is shown in Figure 7-3 and Figure 7-4. The details of the HVDC technology and their characteristics are discussed in later sections. Figure 7-3: Back-to-Back HVDC Converter Arrangement Figure 7-4: HVDC Transmission Line Arrangement 8. STUDY APPROACH AND SCENARIOS The overall study scope assesses 100 MW, 150 MW and 200 MW options for a Peru-Chile interconnection and puts forth a potentially optimal rating for the interconnection based on the estimated economic benefits. The approach evaluates the potential technical feasibility of all three ratings and identifies the system improvements that may be needed on both Peruvian (SEIN) and Chilean (SING) systems. It also estimates project costs for the interconnection, including system upgrade costs. The estimated project and operation and maintenance costs for Page 13

19 all three scenarios are in turn used in the companion planning analysis entitled The Peru-Chile Interconnector: Planning Analysis Study Report. As agreed upon between the Chilean and Peruvian counterparts, the in-service date for the interconnection will be assumed as 2020 for this analysis. Assumptions in terms of transmission expansion plans were based off Peruvian and Chilean national studies conducted by the national regulators and system operators as well as working sessions with the counterparts in October 2014 and March SEIN and CDEC-SING provided their system models in the DigSilent Power Factory format. The following system data were used for the technical analysis: Demanda Alta 2020 Power flow data set for the SING system corresponding to 2020 AV22max Power flow data set for the SEIN system and scaled to 2020 The following system analyses were performed for the three interconnection alternatives: Steady state power flow analysis Fault Analysis Transient Stability Analysis The Peruvian and Chilean grid codes were used as the basis for assessing the performance of the interconnection alternatives. 9. SYSTEM ANALYSIS The intent of this analysis is to identify whether there would be any overload or voltage issues during the normal operating condition and also during the N-1 (single contingency) condition with the proposed interconnection in place Steady State Power Flow Analysis Steady state power flow analysis provides information about power flows on transmission lines and transformers. The new thermal generators in Southern Peru, the new 220 kv line from Condores to Parinacota in Chile, and the interconnection were included in the DigSilent model. Appendix 1 demonstrates the one line diagrams of the power flow model near the interconnection project. For the purpose of the studies, the HVDC converters were assumed to be of thyristor-based converters. The HVDC technologies and their applicability for the Chile Peru interconnection is discussed in later sections. HVDC converters absorb a lot of reactive power for their operation and they are about 45% to 55% of a converter s ratings. This reactive power needs to be supplied by harmonic filters and shunt capacitors. In addition to the converters, the AC system may also require additional reactive power support, depending on the power flow conditions. Power flow analysis was performed to identify the reactive power required to support the interconnection and Table 9-1 shows the amount of reactive power required at Los Heroes and Parinacota. Page 14

20 Table 9-1: Amount of Reactive Power Required at the Converter Stations Interconnection Rating (MW) Los Heroes (MVAR) Parinacota (MVAR) Table 9-1 indicates that additional reactive power is required at Los Heroes at higher interconnection ratings. About 25 MVAR of additional reactive power is required for the 150 MW interconnection option and about 50 MVAR for the 200 MW interconnection option. This additional reactive power requirement is due to the higher reactive voltage drop on Montalvo Los Heroes lines at higher power transfers. N-1 contingency analysis was performed for both SEIN and SING systems with the interconnection in place. A single transmission line, transformer, and generator were considered for the analysis. Table 9-2 presents the system constraints that were identified for the three interconnection levels. The table also provides possible mitigation measures. Interconnection Level Table 9-2: Identified System Constraints Contingency Impact Mitigation 100 MW, 150 MW and 200 MW Montalvo 500/230 kv transformer System instability A second transformer is planned to be installed in Until such time, the HVDC converter shall be tripped for the loss of the Montalvo 500 kv transformer. 150 MW and 200 MW Montalvo Los Heroes 220 kv line The other Montalvo Los Heroes 220 kv line overloads DC power needs to be ramped down. There were no issues identified on the SING system with regards to the contingency analysis. The implementation of the second 220 kv line from Condores to Parinacota, however, is very important for the project. If this second line is not in place before the interconnection project, studies show that the DC tie will have to be tripped whenever the Parinacota Condores 220 kv line is tripped. Page 15

21 9.2. Fault Analysis Due to their technical sophistication, HVDC converters do not contribute to fault current levels. Therefore, the new interconnection will most likely not have an impact on the existing fault current levels in the SEIN and SING systems. A fault analysis was performed and fault currents were calculated at Parinacota 220 kv and Los Heroes 220 kv buses using the same models that were used for the power analysis. Table 9-3 shows the calculated fault current values. Bus Table 9-3: Calculated Fault Currents Three Phase Fault Current Parinacota 220 kv Los Heroes 220 kv 2100 A 2983 A SEIN and CDEC-SING provided the fault current values based on their respective current generation and transmission expansion plans. The estimated three phase fault current at Los Heroes 220 kv bus by 2020 is 3300 A. Table 9-4 shows the three phase fault current values provided by SING for different future scenarios at the Parinacota 220 kv substation. Table 9-4: Three Phase Currents at Parinacota by 2020 Scenario Fault Current With Generation Expansion in North Area and CTTAR in service Without Generation Expansion in North Area and CTTAR in service Without Generation Expansion in North Area and CTTAR out of service 1950 A 1150 A 1090 A The calculated fault current values are used to evaluate the AC system strength in the following sections Transient Stability Analysis Transient stability analysis is generally completed to assess the performance of a system during major disturbances such as faults. At the feasibility study stage, such as this study, a transient stability study for an AC/DC system provides only an indication of system recovery behavior following a major disturbance, but is not a definitive study. Further studies will be required during the design stage with more realistic and detailed HVDC controller models provided by the HVDC converters suppliers. Page 16

22 Transient stability studies were performed for all three interconnection levels for the following scenarios, which are considered to be critical disturbances: Three phase fault at the Parinacota Condores 220 kv line, closer to Parinacota, followed by tripping of the line Three phase fault at the Los Heroes Montalva 220 kv line #1, closer to Los Heroes, followed by tripping of the line Three phase fault closer to the Peruvian converter station, followed by tripping of the interconnector Three phase fault closer to the Chilean converter station, followed by tripping of the interconnector In all the cases studied, the system recovered from the disturbance and remained stable. No dynamic reactive power devices are expected as part of the interconnector. The transient stability study plots are provided in Appendix HIGH VOLTAGE DC (HVDC) TECHNOLOGIES In this section, HVDC technologies are discussed with respect to their application and system requirements History of HVDC Systems The first commercial modern era HVDC transmission line was commissioned in Sweden in 1954 between the island of Gotland and the mainland. It used the high power mercury arc valves for AC/DC/AC conversion, which were the backbone of the then HVDC technology. Following the success of the Gotland project, several HVDC systems were installed using the mercury arc valve technology, including the Cross Channel project between England and France and the Pacific DC Intertie in the United States. The development of high voltage, high power semiconductor devices in the 1960s introduced the first commercial solid state semiconductor valve for HVDC transmission in Since then, the semiconductor thyristor (valve) technology has been growing steadily which has made the HVDC transmission line a proven and reliable alternative for AC transmission. At present, the highest DC transmission voltage is +/- 800 kv utilized in China and India. In recent years, HVDC systems using other power electronic devices have also been used for specific applications HVDC Process The fundamental process that takes place in HVDC systems is the conversion of AC voltage to DC voltage and vice versa. The current HVDC technology can be classified into two broad categories based on the components used for the conversion: 1. Classic HVDC systems use high voltage, high power solid state thyristors. These systems are also generally referred to as Line Commutated Converters (LCC). Sometimes, series capacitors are added between the converters and the converter transformers if the AC system has a low short circuit level (weak system), in which case the AC/DC converters are called Capacitor Commutated Converters. Page 17

23 2. Voltage Source Converter technology uses power electronic devices such as Gate Turn Off thyristors (GTO) and Insulated Gate Bi-polar transistors (IGBT). Even though these devices have been in use in industrial environments for over two decades, their application in HVDC transmission has been recognized only in the last decade. HVDC Light and HVDC PLUS are some of the trade names used for this kind of technology HVDC Applications In almost all of the existing HVDC installations, DC transmission was chosen over AC transmission either due to economic reasons or due to technical considerations. The following are the main reasons for using HVDC transmission systems: 1. When bulk power needs to be transported over a long distance, the overall cost of DC transmission, including the cost of converters, filters, overhead lines and losses, will usually be lower than the cost of overhead AC transmission. Studies have shown that for a power transfer of 1000 MW, an overhead DC transmission line will be a more economical choice than AC transmission if the distance exceeds about 375 miles. This distance is often referred to as breakeven distance. 2. For underground (UG) transmission systems of lengths greater than miles, it may not be practical to use AC cable systems without a large amount of shunt reactive compensation due to the presence of high charging current. HVDC UG cable systems would be an option in such applications, 3. Some AC electric power systems are not synchronized to their neighboring electric systems even though the physical distance between them is quite small. This situation can arise if the adjacent systems have two different frequencies (50 Hz and 60 Hz) such as in Chile and Peru or due to asynchronous operation considerations such as between the Western and Eastern systems of the United States. In such situations, a DC interconnection is the only practical solution for the overall interconnected operation. 4. In some instances, HVDC transmission has been preferred over AC transmission due to the fact that the HVDC connections do not add to the existing fault levels. One such example is the Kingsnorth project in the United Kingdom. In deregulated electricity marketplaces, DC transmission systems are also being considered to connect different control areas due to its ease of power flow control between the systems. For example, a DC transmission line between Queensland and New South Wales in Australia was installed to enable controlled electricity trading between the two states Back-to-Back HVDC Converters In many applications, such as in integrating two asynchronous AC systems or reducing fault current levels, there may not be a need for an overhead transmission line or an underground cable system. The requirement in this case is a transformation from AC to DC (rectifier) and then from DC to AC (inverter). The converters for these applications would be housed in the same building. These installations are commonly called Back-to-Back converters. Back-to-Back HVDC systems can be designed for bi-directional power flow and they also have the advantage of not requiring any ground electrode systems. These devices can also be used Page 18

24 to interconnect two control areas, such as SEIN and SING, controlling power flow without increasing the fault levels of either system Line Commutated Converters (LCC) / Current Source Converters (CSC) Current Sourced Line Commutated Converters are also referred to as Classic HVDC Schemes. The basic building block that is used in these types of installations is a 6-pulse bridge converter. In order to keep the harmonic current levels low, two 6-pulse converters are connected in series on the DC side and the phase displaced by 30 on the AC side to provide a 12-pulse configuration. In LCC schemes, 12-pulse converters are the standard arrangement. High power thyristors are used to configure the bridge converters and several thyristor modules are connected in a series and parallel combination to achieve the required voltage and power ratings. Thyristor converters produce both AC and DC harmonics. For a 12-pulse arrangement, the dominant AC harmonics are 11 th, 13 th, 23 rd, 25 th and higher order harmonics. On the DC side, the dominant harmonics are 12 th and 24 th harmonics. For the back-to-back converter stations, the DC harmonics are not of concern as opposed to a scheme with a DC transmission line. Large harmonic filter banks are required on the AC terminals of the converters in order to suppress the amount of harmonic currents that can penetrate the AC system. These filters are required for the converters regardless of whether they operate as a rectifier or an inverter. At times, additional 3 rd harmonic filters may be required in addition to the dominant harmonic filters. LCCs require a large amount of reactive power for their operation. That is, these converters consume a large amount of reactive power similar to inductive loads. This reactive power will have to be supplied either by the AC system (the power grid) or by additional shunt capacitor banks. Typically, the reactive power requirement would be about 45% to 55% of the active power that is being transmitted. For example, for a 200 MW back-to-back converter system, the reactive power requirement would be about 90 MVAR to 110 MVAR on each side (rectifier and inverter). Some of this reactive power (about 30% to 40%) may be supplied from the harmonic filter banks. Figure 10-1 shows a typical LCC converter station s main components: Page 19

25 Figure 10-1: Typical LCC Converter Station 2 Bidirectional power flow is possible with this type of converter and is achieved by reversing the DC voltage polarities and maintaining the same current direction. LCC based schemes require synchronous voltage sources for their operation or in other words, grid voltage must exist on both the sending end and the receiving end. Hence, these types of schemes cannot be used for black-start applications Voltage Source Converters (VSC) / Forced Commutated Converters Voltage Sourced / Forced Commutated Converters are sometimes also referred to with manufacturer s trade names such as HVDC Light and HVDC PLUS. The basic building block that is used in these types of installations is a forced commutated converter using a DC capacitor, as shown in Figure Figure 10-2: Two-Level Forced Commutated Converter Many different configurations based on the one shown in Figure 10-2 have been applied for HVDC applications and the motivation has always been to reduce the lower order harmonic currents and the switching losses. Some of the commonly applied configurations are: 2-level converters with pulse width modulation (PWM) techniques, and cascaded 2-level converters with PWM, 3-level and multi-level modular converters. Insulated Gate Bipolar Transistors (IGBT) are presently used in the VSC converter schemes. Many individual IGBTs are used in series and parallel configuration to achieve the required voltage and power ratings. VSC converters only produce higher order harmonics and the harmonics are very little in magnitude. Depending on the converter configuration adopted, harmonic filters may or may not be required. Bidirectional power flow is possible with the VSC converters by reversing the DC current direction and by keeping the same DC voltage polarities at the converters. Voltage Source Converters can either absorb or supply reactive power, regardless of the power flow direction. It is also possible to operate the VSC converters as two independent STATCOM devices for voltage regulation, if the DC link is out of service. VSC converters do not require shunt capacitors for reactive power compensation. Figure 10-3 shows a typical VSC HVDC converter station arrangement. 2 ABB Publication, The ABC s of HVDC Transmission Technologies, IEEE Power & Energy Magazine, March/April 2007 Page 20

26 Figure 10-3: Typical VSC HVDC Converter Station Arrangement 3 VSC based schemes do not require synchronous voltage sources for their operation, or in other words, grid voltage need not exit on the receiving end. Hence these types of schemes can be used for black-start applications. Figure 10-4 shows a typical back-to-back VSC arrangement. Figure 10-4: Typical Back-to-Back VSC Arrangement Comparison of Technologies Table 10-1 provides a comparison of the VSC and the LCC technologies. Table 10-1: Comparison of the HVDC Technologies Feature State of Technology Voltage Source Converter (VSC) Technology Relatively newer technology (in commercial operation since late 1990s). Line Commutated Converter (LCC) Technology Older and matured technology which uses line-commutation (in existence since 1950s). 3 ABB Document, The ABC s of HVDC Transmission Technologies, IEEE Power & Energy Magazine, March/April 2007 Page 21

27 Feature Design Basis Principles of Operation Voltage Source Converter (VSC) Technology Requires devices with turn-off capability such as Insulated Gate Bipolar Transistors (IGBT s) and pulse width modulation (PWM) for IGBT switching. Bidirectional power flow control achieved by reversing the DC current polarity and keeping constant the DC voltage polarity (supported by a DC capacitor). Line Commutated Converter (LCC) Technology Implemented using thyristor valves (line-commutated). Bidirectional power flow control achieved by reversing DC voltage polarity and keeping constant DC current polarity (supported by DC inductor). Performance The DC voltage is converted to AC voltage through sequential switching with variable amplitude and phase angle with the system AC voltage. Does not require reverse blocking valves since the DC voltage maintains constant polarity. The DC current is converted to AC current through sequential switching with variable amplitude and phase angle with the system AC current. Due to the bidirectional DC voltage, CSC valves require both forward and reverse blocking. Reactive Power Requirement Converter Losses Provides numerous benefits to overall system performance, including: Rapid and independent control of both real and reactive power. No restrictions regarding minimum network three phase short circuit capacity. If properly equipped, can be utilized for black start, i.e. converter station can be used to generate balanced three phase voltages. Reactive power can be controlled (produced/consumed) to regulate AC system voltage at each converter station bus. Relatively higher Requires synchronous, relatively strong voltage source for proper operation (i.e. in order to commutate properly): Rule-of-thumb: three phase network short circuit capacity should be at least twice the converter rating. Reactive power is provided through AC filters, shunt banks, or series capacitors in order to achieve a stiff AC bus voltage. Can only operate with AC current lagging voltage; therefore, the conversion process demands reactive power. Reactive power is supplied through a combination of AC filters, shunt banks, or series capacitors. Relatively lower Cost Relatively higher Relatively lower Footprint Relatively smaller Relatively larger 11. SHORT CIRCUIT RATIO (SCR) The Short Circuit Ratio (SCR) is a measure of AC system strength to which HVDC converters are connected. It is normally defined as the ratio of Short Circuit MVA to the Converter Rating, as given by: Page 22

28 SCR = Short Circuit MVA / Converter Rating (MW) The capacitors and filters at the converter bus reduce the short circuit level and hence an Effective SCR (ESCR) is defined and is given by: ESCR = (Short Circuit MVA Shunt Reactive Power) / Converter MW In the case of low ESCR, the changes in the AC network or in the transmitted power could lead to voltage oscillations and may require special control strategies or dynamic reactive power compensation such as synchronous condensers or Static VAR Compensators (SVC). Generally an ESCR below 2.0 is considered to be low for a thyristor-based HVDC scheme. Voltage Source Converter (VSC) schemes do not have any such restrictions with respect to SCR. Effective Short Circuit Ratios were calculated for the three interconnection levels based on the required shunt reactive power and fault levels calculated in Section 9.1 and 9.2 and they are shown in Table Table 11-1: Calculated Effective Short Circuit Ratios (ESCR) Interconnector Level ESCR at Los Heroes ESCR at Parinacota 100 MW MW MW The calculated ESCR at Parinacota for a 200 MW interconnection level is lower than the required value of 2.0 for thyristor based HVDC schemes. For a 200 MW rating, a type of dynamic reactive power compensation device, such as synchronous condenser or Static VAR Compensator (SVC), will be required. Alternatively, Voltage Source Converter (VSC) HVDC may be considered for this rating. This report estimates that a synchronous condenser rating of 30 MVA will be required at Parinacota to provide the required short circuit rating. If redundancy is required, then 2 x 30 MVA synchronous condensers will be needed at Parinacota. 12. CONCEPTUAL INTERCONNECTOR PROJECT ARRANGEMENT Given discussions with both system operators, the proposed Chile Peru interconnector could either be a back-to-back HVDC converter station with AC lines or an HVDC interconnection, depending on whether one entity (SEIN or CDEC-SING) will operate and maintain the back-toback converter station or whether it will be split between them by having two independent converter stations. In either case, three possible ratings, i.e., 100 MW, 150 MW and 200 MW are considered. The final rating will be based on the economic analysis and the economic benefit accruing to the participating countries. Regardless of the final rating, the conceptual project one line diagrams for the back-to-back and the HVDC line alternatives are shown in Figures 12-1 and The technical specifications for the agreed upon line rating for both the back-to-back and the HVDC line alternatives are provided in a separate report under this Department of Statefunded project. Page 23

29 Figure 12-1: Conceptual One Line Diagram for Back-to-Back HVDC Converter Station Figure 12-2: Conceptual One line Diagram for the HVDC Transmission Line Option The proposed arrangement for the HVDC line interconnection is a bi-pole arrangement. If the system operators consider a plan for expanding the interconnection in the future, for example to 400 MW, then a suitable initial HVDC configuration should be a monopole configuration, which could later be expanded to bi-pole for the larger interconnection alternative. 13. ESTIMATED COST FOR THE INTERCONNECTOR The estimated potential budgetary cost for the back-to-back HVDC interconnection for the different ratings is shown in Table Page 24

30 Table 13-1: Estimated Cost for the Back-to-Back HVDC Converter Option 4 Item 100 MW Interconnection (million US$) 150 MW Interconnection (million US$) 200 MW Interconnection (million US$) Thyristor based Back-to-Back Converter Station 33 km, 220 kv AC transmission line in Peru 22 km, 220 kv AC transmission line in Chile AC substation upgrade at Los Heroes AC substation upgrade at Pariancota 30 MVA Synchronous Condenser, - 11 transformer and switchgear Total EPC Cost (sum of the above) Non EPC Cost such as financing, Owners cost, etc. (15%) Total Project Cost The estimated budgetary cost for the HVDC interconnection for the different ratings is shown in Table Table 13-2: Estimated Cost for the HVDC Transmission Line Option Item 100 MW Interconnection (million US$) 150 MW Interconnection (million US$) 200 MW Interconnection (million US$) Thyristor based Converter Stations km, HVDC transmission line AC substation upgrade at Los Heroes AC substation upgrade at Pariancota 30 MVA Synchronous Condenser, - 11 transformer and switchgear Total EPC Cost (sum of the above) Non EPC Cost such as financing, Owners cost, etc. (15%) Total Project Cost The cost of VSC converters are estimated to be about 30% more than the cost of thyristor based converters. 4 The indicated costs are based on the budgetary costs received from the three major HVDC vendors (ABB, Siemens and Alstom). HVDC project costs generally vary between regions and are based on the demand at the time of the project. Page 25

31 MW INTERCONNECTION A second interconnection between Peru and Chile, assumed to be in service by 2024, was studied as a sensitivity case. This project was considered to be a 1000 MW, +/- 500 kv HVDC transmission line from Montalvo in Peru to Crucero in Chile. Figure 14-1 shows this second interconnection between Peru and Chile. The approximate length of this transmission line is 607 km. Figure 14-1: 1000 MW Interconnection between Peru and Chile The following power flow models were used to analyze the impact of the 1000 MW interconnection on the SEIN and SING / SIC systems: AV22max Power flow data set for the SEIN system and scaled to 2024 SIC_2014_2022 Power flow data set for the SING and SIC systems; a proposed 500 kv AC line between Mejillones (in SING system) and Cardones (in SIC system) was included in the model and loads were scaled up by 15% from the 2020 load. Page 26

32 N-1 contingency analysis was performed for both Peru and Chilean systems with the 1000 MW and the 200 MW Back-to-Back HVDC Converter interconnections in place. A single transmission line, transformer, and generator outage were considered for the analysis. Table 14-1 presents the system constraints that were identified. The table also provides possible mitigation measures. Table 14-1: Identified System Constraints for 1000 MW Interconnection System Contingency Impact Mitigation SEIN 1000 MW Interconnector System instability Trip 500 MW generation near Montalvo area SING 1000 MW Interconnector System Instability Trip 160 MW load in Crucero area SING Any 220 kv line connected to Crucero System Instability A new 500 kv line from Crucero to Mejillones is required or HVDC power needs to be ramped down during N-1 contingencies. The power flow solutions did not converge (which indicates system instability) for the loss of any 220 kv transmission line connected to the Crucero substation in Chile. This means that additional transmission lines will be required near Crucero to accommodate the 1000 MW interconnection. Alternatively, the HVDC power can be ramped down in the event that a loss of a line connected to Crucero occurs. After the completion of this technical analyses, CDEC-SING provided an updated DigSilent model with their transmission expansion plan until 2024, which also included a 500 kv transmission line from Crucero to Mejillones. It was confirmed that this 500 kv line and the SING-SIC interconnector would be essential to support the 1000 MW interconnector, otherwise HVDC power will need to be ramped down for any 220 kv line outage. The Short Circuit Ratio (SCR) at Montalvo, Peru is more than 3 and hence, there will not be any need for additional dynamic reactive power compensation. The SCR at Crucero, Chile is undetermined at this time, however it is anticipated that a synchronous condenser of 100 MVA will be necessary to provide the required SCR. The steady state studies have indicated that it would be feasible to operate both the 200 MW Back-to-Back and the 1000 MW HVDC interconnector together. Detailed transient stability studies will have to be performed during the design phase to identify the controllers that will be required for proper operation. The estimated budgetary cost for the 1000 MW HVDC interconnection is shown in Table Page 27