103719 Smart Grid to Enhance Power Transmission in Vietnam Asia Sustainable and Alternative Energy Program Energy Sector Management Assistance Program Smart Grid to Enhance Power Transmission in Vietnam February 2016 Smart Grid to Enhance Power Transmission in Vietnam Publication of the International Bank for Reconstruction and Development/The World Bank Supported by the Asia Sustainable and Alternative Energy Program (ASTAE) and Energy Sector Management Assistance Program (ESMAP) Copyright © 2016 /  The International Bank for Reconstruction and Development  The World Bank 1818 H Street, NW Washington, DC 20433, USA Telephone: (202) 473-1000 Fax: (202) 522-2422 Internet: www.worldbank.org All rights reserved This volume is a product of the staff of the International Bank for Reconstruction and Development/the International Development Association/The World Bank. 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Master Table of Contents ACKNOWLEDGEMENTS..............................................................................................................v EXECUTIVE SUMMARY.............................................................................................................vii VOLUME 1: TECHNICAL ANALYSIS.............................................................................................1 VOLUME 2: COST-BENEFIT ANALYSIS...................................................................................131 VOLUME 3: REGULATORY AND PERFORMANCE MONITORING.........................................221 iii Acknowledgements This report was prepared by CESI International under the The World Bank team would like to thank Vietnam’s supervision of a World Bank task team that included Peter National Power Transmission Corporation (NPT), the Johansen (Task Team Leader and Senior Energy Spe- Electricity Regulatory Authority of Vietnam (ERAV), and cialist), Hung Tan Tran (Co-Task Team Leader and Power Vietnam’s National Load Dispatch Centre (NLDC) for their Engineer), Debabrata Chattopadhyay (Senior Energy Spe- collaboration and candid feedback. cialist), and Roberto La Rocca (Energy Specialist). Finally, the World Bank would like to gratefully acknowl- The team is grateful for the valuable contributions of edge the contributions of the Asia Sustainable and Franz Gerner (Lead Energy Specialist), Marcelino Mad- Alternative Energy Program (ASTAE) and the Energy rigal (Senior Energy Specialist), Maria Elisa Passeri (Con- Sector Management Assistance Program (ESMAP) for sultant), Elisa Malerbi (Consultant) and Hoa Chau Nguyen their financial support towards the preparation of this (Team Assistant). publication. v Executive Summary Over the last few decades Vietnam has made remarkable demand and official demand forecast as presented in progress in reducing poverty and positioning its economy Vietnam’s Power Master Development Plan (PMDP) VII. on a sustainable growth path. Political and economic reforms (Doi Moi) launched in 1986 have transformed With electricity consumption nearly matching genera- Vietnam from one of the poorest countries in the world, tion in recent years and insufficient investment in new with per capita income below $100, to a lower middle power plants, the electricity grid is under constant strain income country within a quarter of a century with per by the growing economy. Realizing the large technical, capita income of over $2,000 by the end of 2014. Viet- institutional and financial challenges posed by this level nam’s growth rate has averaged 6.4% per year for the of expansion will be a key priority for Vietnam’s grid sys- last decade and the percentage of people living in pov- tem operators in the short term. Moreover, the planned erty dropped from almost 60% in the 1990s to less than addition in the longer term of renewable energy technol- 3% today. ogies to the energy mix will pose further challenges to the efficient delivery of electricity to a growing customer As a consequence of robust economic growth, electricity base. Facing these challenges will require the adoption of demand in Vietnam grew at an average of 14% annually innovative solutions such as the ones provided by Smart over the last decade. Despite the recent economic slow- Grid technologies. down, post-2009 electricity demand has continued to grow 10% annually reaching 119 billion kWh in 2012 and In 2012, the Government of Vietnam (GoV) approved the is anticipated to increase to 320 billion kWh in 2020 and “Smart Grid Development Project in Vietnam” which out- 690 billion kWh in 2030 respectively. Per capita electric- lines a Smart Grid Roadmap for Vietnam. The Project is ity consumption remains low in Vietnam at 1,035 kWh in aimed at the integration of new monitoring, protection 2012 compared to 2,224 kWh in Thailand and 2,942 kWh and control systems to improve grid reliability and make in China. Figure 1 shows the development of electricity efficient use of infrastructure while facilitating future FIGURE 1 VIETNAM’S ELECTRICITY DEMAND 350,000 300,000 250,000 200,000 GWh 150,000 100,000 50,000 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 −50,000 Year Electricity demand (GWh) Linear electricity demand (GWh) Source: Vietnam PMDP VII. vii viii Smart Grid to Enhance Power Transmission in Vietnam TABLE 1  TECHNICAL BENEFITS OF SMART GRID TECHNOLOGIES Smart Grid Initiative Technical Benefits SAS, including remote control 60% reduction of OPEX for the transmission system 1 centers Average reduction of ENS2 by 100 MWh/y per substation equipped WAMS 10% reduction of OPEX for the transmission system 20% less faults if all substations are equipped with PMUs3 LLS 5% reduction of OPEX for the transmission system 25% reduction of phase-to-phase-to-ground faults caused by lighting SVC 10% reduction of OPEX for the transmission system 25% reduction of voltage collapse events FLS 25% reduction in time taken to attend and repair the fault DGA 80% of faults prevented by equipping a transformer with a DGA device DTCR 5% reduction of OPEX for the transmission system GIS 10% reduction of total OPEX of the SAS project Power Quality Monitoring and 5% reduction of OPEX for the transmission system Metering Data Acquisition 20% reduction of fault times Systems Source: Authors Notes: 1 Operational Expenses 2 Energy Not Served 3 Phase Measurement Units integration of scaled-up renewable energy options. The Lighting Location System (LLS); (iv) Static Var Compen- National Power Transmission Corporation (NPT) has sator (SVC); (v) Fault Locator System (FLS); (vi) On-line already started progressing some of the Smart Grid initia- Dissolved Gas-in-oil Analysis (DGA); (vii) Dynamic Ther- tives for transmission identified in the roadmap, such as, mal Circuit Rating (DTCR); (viii) Geographic Information the deployment of Substation Automation System (SAS) Systems (GIS); and (ix) Power quality monitoring and and Wide Area Monitoring Systems (WAMS) as well as Metering Data Acquisition Systems. Table 1 highlights an information system for operation and supervision. the technical benefits coming from the adoption of these Smart Grid technologies. To support GoV’s efforts, the World Bank has closely engaged with NPT, the Electricity Regulatory Authority In addition to Smart Grid technologies, High Voltage of Vietnam (ERAV) and the National Load Dispatch Cen- Direct Current (HVDC) technology is also considered in ter (NLDC) to refine the existing Smart Grid roadmap on the analysis. The construction of a new HVDC line is not the basis of the lessons learned from the international a Smart Grid initiative itself, but the choice of the HVDC experience with Smart Grid development. This report technology for building over planned conventional AC presents the results of this technical assistance engage- lines introduces certain desirable characteristics in the ment funded by the Energy Sector Management Assis- grid to render it more secure. The design of the grid tance Program (ESMAP) and the Asia Sustainable and therefore is smart and the incremental benefits associ- Alternative Energy Program (ASTAE) and consists of: (i) a ated with the HVDC line over the planned AC line have technical analysis of Vietnam’s existing Smart Grid road- been considered in the analysis. In particular, the adop- map, and alternative and future options (Volume 1); (ii) tion of HVDC can contribute to reduce the transmission cost-benefit and risk analyses of the Smart Grid options system OPEX by 5%. identified in the technical analysis (Volume 2); and (iii) considerations of regulatory and performance monitor- The cost-benefit analysis performed shows that all identi- ing (Volume 3). fied Smart Grid solutions have positive Net Present Values (NPVs). Table 2 summarizes the results of the analysis for The report proposes a revised Smart Grid roadmap con- each Smart Grid initiative based on the assumed scale of taining the following components: (i) SAS; (ii) WAMS; (iii) each operation. Executive Summary ix TABLE 2  COST-BENEFIT ANALYSIS OF SMART GRID TECHNOLOGIES Capital Cost Smart Grid Initiative (USD mln) NPV (USD mln) IRR4 Scale of Operation SAS, including remote 147.9 179.0 41% 18 retrofits control centers 150 new SAS WAMS 1.3 23.0 204% 224 PMU installed at 500 kV and 220 kV voltage level LLS 1.4 11.0 164% 20 detectors monitoring lightning activity across the country SVC 25.0 5.3 14% 900 Mvar SVCs installed in the most affected areas of Vietnam FLS 7.3 1.2 13% 140 Fault Locators DGA 41.7 5.5 12% 732 transformers equipped, (includes current and new) DTCR 1.1 44.1 Positive Cash Flows 40 sensors monitoring 400 km lines GIS 0.2 0.8 48% Geographic information of power system components throughout Vietnam Power Quality 0.2 11.0 797% 105 power quality measurement Monitoring and devices at 500 kV and 220 kV Metering Data voltage level Acquisition Systems Source: Authors The cost-benefit analysis of HVDC reported incremental regulatory. Technical KPIs include performance indicators capital costs amounting to approximately $13.3 million and threshold level. Economic KPIs are measured against and an NPV of about $23.5 million based on a 2,000 MW a benefit/cost ratio. Regulatory KPIs are measured on dif- interconnection for 800 km of length. ferent levels (initiative, system, and program) and consist of measurable deliverables. Table 4 summarizes the tech- The risk analysis shows that the initiatives with the high- nical KPIs. est relative risk profile are: SAS, WAMS, LLS, SVC, FLS, DGA and Power Quality Monitoring and Metering Data The performance indicator identified for High Voltage Acquisition Systems. Risk mitigation actions for high-risk Direct Current technology is Power Factor with an asso- initiatives are presented in Table 3. ciated technical KPI threshold of 0.7. Risk mitigation actions identified for HVDC are to: (i) The implementation of the Smart Grid roadmap requires engage with the planning department to choose optimal a set of activities to be performed by the different par- installation sites; (ii) develop a proper system operation ticipants involved (ERAV, NPT, and NLDC) on the road- strategy to fully exploit the HVDC links; and (iii) perform map activities until the completion of the program. As electricity market studies for the medium and long term in illustrated in Table 5, overall implementation coordina- order to better estimate the cost of energy and investigate tion rests with NPT. Together with NLDC, NPT would be potential profitable connections with foreign countries. responsible for the incorporation of the refined roadmap in high level planning activities. ERAV is expected to play Following the risk analysis, Key Performance Indicators a central role in the final approval of the Smart Grid initia- (KPIs) aimed at carrying out performance and impact tives identified (which would then be up for inclusion in monitoring of the Smart Grid Program were identified at the Master Plan by the Institute of Energy (IE)) and closely three different levels: (i) technical; (ii) economic; and (iii) monitor their performance during implementation. x Smart Grid to Enhance Power Transmission in Vietnam TABLE 3  RISK MITIGATION ACTIONS FOR SMART GRID INITIATIVES Smart Grid Initiative Mitigation Action SAS, including remote control • Link the final commissioning of new substations with the complete commissioning of their centers SAS equipment • Manage the gap between the roadmap and real installation pace • Streamline the SAS automation installation process to target the most critical areas first. Monitor the performance of the already implemented SAS for a better estimation of the ENS saved and a reduction of the investment uncertainty WAMS • Expedite the development of the remote control center • Focus investments on developing applications based on WAMS data • Streamline the Phase Measurement Unit installation process to target the most critical lines. Monitor the performance of the installed PMUs for a better estimation of the faults that can be avoided and a reduction of the investment uncertainty LLS • Expedite the development of the remote control center • Focus investments on developing applications fed by LLS data and carry out adequate training for the control room operators to exploit LLS information • Optimize the positioning of the sensors in order to cover the whole network SVC • Engage with the planning department to choose optimal installation • Re-locatable SVCs can easily solve the problem of site selections that are either not the best fit for purpose or those sites that are temporarily for purpose • Develop a planning activity for the SVC initiative in order to improve the reactive compensation starting with the most critical areas • Use the first implementations for data collection and reduction of investment uncertainty FLS • Expedite the installation for the most critical lines • Manage the gap between the roadmap and real installation pace • Optimize the planning activities in order to implement the FLS on those lines with the highest maintenance cost. Monitor the already implemented FLS’s for a better estimation of the average reduction outage time duration that is possible with this initiative DGA • Align the final commissioning of new transformers and their DGA equipment • Manage the gap between the roadmap and real installation pace • Optimize the planning activities in order to implement the DGA on those transformers with the highest cost of repair and those with the highest fault probability. Monitor the already implemented DGA’s for a better estimation of the benefits that can be obtained with this initiative Power Quality Monitoring and • Expedite the installation on the most critical areas Metering Data Acquisition • Develop a clear regulatory policy focused on the relationship with the electricity generation Systems function to ensure maximum synergy under critical conditions • Develop a planning activity for the initiative in order to reduce the unserved energy starting with the most critical areas Source: Authors Executive Summary xi TABLE 4  TECHNICAL KEY PERFORMANCE INDICATORS FOR SMART GRID INITIATIVES Smart Grid Initiative Performance Indicator Satisfactory Threshold Energy Not Served (ENS) reduction per year for each SAS 100MWh substation equipped with SAS Voltage collapse prevention 15%-35% WAMS Out-of-steps prevention 15%-35% Percentage reduction of transient faults affecting the LLS 20%-30% lines 95% variation interval of voltage level of network “pilot +/-5% of the rated voltage nodes” SVC Voltage collapse prevention 15%-35% Reduction of time to attend fault site by maintenance FLS 25% crew and elapsed time to repair DGA Fault number reduction 80% DTCR “Ampacity” increase 5%-25% GIS Reduction of management costs 10%-15% Power Quality Monitoring System Percentage reduction of voltage dips 20% Mean square error between the value acquired by the Metering Data Acquisition System meters and the value calculated by the settlement for 0.4%-0.8% the same meters Source: Authors TABLE 5  ROLES AND RESPONSIBILITIES OF THE REFINED ROADMAP Activity NPT NLDC ERAV IE Internally approve the Refined Roadmap R R Present the Final Report to other institutions R I I I Define the priorities for Implementation in the short-term R R A Request approval of the Smart Grid initiatives from the regulator R R A Approve Smart Grid initiatives C C R I Based on the KPIs recommended, define the final targets of KPIs for the implementation C C R Include the approved investments in the Master Plan CA CI I R Follow up the approved Smart Grid investments through the KPIs CI CI R Source: Authors R = Responsible; A = Accountable; C = Consulted; I = Informed xii Smart Grid to Enhance Power Transmission in Vietnam Finally, the legal and regulatory environment for the policy; (iv) Quality of Service regulatory policy (indicators, revised Smart Grid roadmap was analyzed in the areas incentives, penalties); and (v) Smart Grid Policy. The main of: (i) System Security policy; (ii) Renewables and their recommendations are summarized in Table 6. policies and incentives; (iii) International Interconnection TABLE 6  LEGAL AND REGULATORY RECOMMENDATIONS Policy Area Recommendation System Security policy The Grid Code should be complemented by the on-line security assessment criteria in order to avoid repeating past errors. Additionally, it should establish the tools that the System Operator must have in order to evaluate the security and perform on-line monitoring and control of the voltage/dynamic stability of the Vietnamese Power System. Renewables and their policies Renewable energy planning should complement the developed Smart Grid roadmap in order and incentives to take advantage of those applications that ease the integration of renewable sources in the transmission network. International Interconnection A greater degree of clarity in this area is needed. This may have some significance for the policy development and deployment of some of the Smart Grid initiatives, e.g., HVDC interconnection, more stringent requirements for online monitoring and security assessment to ensure frequency/voltage problems do not cascade from one system to another, etc. A policy that addresses these points may enable the inclusion of technologies like HVDC and increment the use of SVC for maintaining the stability of the systems and links. Quality of Service regulatory The Grid Code should be revised to include clearly defined penalties for failing or incentives for policy (indicators, incentives, exceeding quality of service requirements. penalties) Smart Grid Policy The Smart Grid policy should complement Decision No.: 1670QĐ-TTg of November 2012 with both KPIs and penalties in order to measure and track the performance of Smart Grid initiatives. Source: Authors 1 Volume 1: Technical Analysis 1 Table of Contents A. Acronym List...........................................................................................................................5 B. Summary of Technical Analysis.............................................................................................7 B.1 Existing Smart Grid Roadmap and Initiatives................................................................................................7 B.2 International Experience and Lessons Learned.............................................................................................8 B.3 Transmission System Enhancements........................................................................................................... 11 B.4 Problems-Solutions Mapping.......................................................................................................................14 B.5 Technical Prioritization and Revised Smart Grid Roadmap........................................................................14 C. Introduction...........................................................................................................................20 C.1 General Overview...........................................................................................................................................20 C.2 Structure of the Document............................................................................................................................21 D. Relevant International Experiences of Smart Grids for Transmission Systems...............23 D.1 Key Points Summary of International Experiences.....................................................................................23 D.2 Italy .................................................................................................................................................................24 D.2.1 Italian Transmission System Organizational Structure Experience ........................................................24 D.2.2 Planning and Asset Management..........................................................................................................25 D.2.3 State Estimation and Security Assessment...........................................................................................25 D.2.4 Defense Plan.........................................................................................................................................26 D.2.5 Load-Frequency regulation.....................................................................................................................27 D.2.6 Automation and Tele-Control for Substations.........................................................................................27 D.2.7 Wide Area Monitoring System...............................................................................................................28 D.2.8 Lightning Location Systems...................................................................................................................34 D.2.9 Power quality monitoring project...........................................................................................................36 D.2.10 Metering Data Acquisition System........................................................................................................37 D.3 Europe.............................................................................................................................................................39 D.3.1 ENTSO–E European Ten-Year Network Development Plan ...................................................................39 D.3.2 Reactive power Compensation in UK – NGC experience .....................................................................43 D.4 USA ................................................................................................................................................................50 D.4.1 Phase Measurement Units—NASPI roadmap.......................................................................................50 D.4.2 Devices for Dynamic Line Rating—NYPA and Oncor DTCR projects....................................................54 D.4.3 Sensors for on-line Dissolved Gas-in-oil Analysis—BC Hydro case.......................................................58 D.4.4 HVDC application—PG&E Example ......................................................................................................59 E. Identification of Viable Solutions for the Vietnamese Transmission Network.................63 E.1 Key Points Summary of solutions identification.........................................................................................63 E.2 Overview of Vietnamese issues and challenges .........................................................................................64 E.3 Transmission System enhancement: pillars for building a Smart Grid ..................................................................64 E.3.1 Planning and Asset Management System basic strategies improvements ..........................................64 E.3.2 State Estimation and N-1 Security Assessment....................................................................................65 E.3.3 Load-Frequency Regulation strategies improvements...........................................................................66 E.3.4 Protections System improvement.........................................................................................................66 E.4 Problems-solutions mapping........................................................................................................................67 3 4 Smart Grid to Enhance Power Transmission in Vietnam F. Description of Smart Solutions Identified..........................................................................69 F.1 Key Points Summary of Smart Grid Solutions............................................................................................69 F.2 New SCADA/EMS system..............................................................................................................................70 F.3 Telecommunications Infrastructure for the Transmission Grid..................................................................71 F.3.1 Wide Area Network for Market Development.......................................................................................72 F.4 Substation Automation System....................................................................................................................72 F.4.1 NPT Substation modernization initiative................................................................................................72 F.4.2 Recommendations for continuous improvement strategy.................................................................... 74 F.4.3 Telecommunication system improvement............................................................................................. 74 F.5 Wide Area Monitoring System......................................................................................................................76 F.5.1 NPT pilot project....................................................................................................................................76 F.5.2 PMU devices selection and their positioning strategy...........................................................................76 F.5.3 Telecommunication system improvement.............................................................................................77 F.5.4 WAMS applications implementation.....................................................................................................78 F.5.5 NPT project evolution............................................................................................................................79 F.6 Lightning Location Systems..........................................................................................................................79 F.6.1 Transmission Lines Surge Arresters......................................................................................................79 F.6.2 Lightning Location using simulation algorithm......................................................................................80 F.6.3 Guidelines for Lightning Location System development in Vietnam......................................................80 F.6.4 Benefits of Lightning Location System data..........................................................................................80 F.7 Static Var Compensators...............................................................................................................................81 F.8 High Voltage Direct Current technology.......................................................................................................85 F.9 Fault Locator System.....................................................................................................................................94 F.10 Power quality monitoring system.................................................................................................................95 F.11 On-line Dissolved Gas-in-oil Analysis for Power Transformers .................................................................96 F.12 Dynamic Thermal Circuit Rating....................................................................................................................98 F.13 Geographic Information Systems.................................................................................................................99 F.14 Metering Data Acquisition System............................................................................................................. 101 G. Technical Prioritization Analysis and Smart Initiatives Metrics.......................................103 G.1 Key Points Summary of Technical Prioritization and Metrics....................................................................103 G.2 Technical prioritization structure.................................................................................................................104 G.3 Time positioning of Transmission System enhancement interventions .......................................................105 G.4 Reasons for technical prioritization and metric identification..................................................................108 Annexes..................................................................................................................................... 112 Annex 1. Functional and Organizational View of Transmission Systems Worldwide..................................... 112 Annex 2. Vietnamese Transmission System ..................................................................................................... 116 Annex 3. FACTS Technology...............................................................................................................................124 References.................................................................................................................................127 Maps, Figures and Tables Sources.................................................................................................................128 Endnotes........................................................................................................................................................129 2 A. Acronym List AC Alternate Current ISO Independent System Operator AMS Asset Management System IE Institute of Energy AVR Automatic Voltage Regulator LAN Local Area Network CCPP Combined Cycle Power Plant LLS Lightning Location System CEER Council of European Energy Regulators LSA Line Surge Arrester CRLDC Central Regional Load Dispatch Center MPI Ministry of Planning and Investment CT Current Transformer MOIT Ministry of Industry and Trade DC Direct Current NASPI North American Synchrophasor Initiative DGA Dissolved Gas-in-oil Analysis NYPA New York Power Authority DLR Dynamic Line Rating NERC North American Electric Reliability Corporation DSA Dynamic Security Assessment NLDC National Load Dispatch Centre DTCR Dynamic Thermal Circuit Rating NPT National Power Transmission corporation EMC Electro-Magnetic Compatibility NRLDC Northern Regional Load Dispatch Center EMS Energy Management System OHTL Over-Head Transmission Line EPRI Electric Power Research Institute PDC Phasor Data Concentrator ENTSO-E European Network of Transmission System Operators for Electricity PMU Phase Measurement Unit ENS Energy Not Served POW Point Of Wave ERAV Electricity Regulatory Authority of Vietnam POD Proper Orthogonal Decomposition EVN Electricity of Viet Nam PQ Power Quality FACTS Flexible Alternate Current Transmission PSS Power System Stabilizer System PTC Power Transmission Company GIS Geographic Information System RES Renewable Energy Source GIS Gas Insulated Switchgear RFI Radio Frequency Interference GOOSE Generic Object Oriented Substation Event RTU Remote Terminal Unit GPS Global Positioning System SAS Substation Automation System GUI Graphical User Interface SCADA Supervisory Control And Data Acquisition HIS Historical Information System SGDP Smart Grid Demonstration Program HVDC High Voltage Direct Current SGIG Smart Grid Investment Grant ICCP Inter-control Centre Communication SO System Operator Protocol SPS Special Protection Schemes IED Intelligent Electronic Device SRLDC Southern Regional Load Dispatch Center IEM Internal Energy Market 5 6 Smart Grid to Enhance Power Transmission in Vietnam S/S SubStation TCSC Thyristor-Controlled Series Compensation STATCOM STATic Synchronous COMpensator UCTE Union for the Coordination of the Transmission of Electricity SVC Static Var Compensator VT Voltage Transformer TLC Telecommunication WAMS Wide Area Monitoring System TLSA Transmission Line Surge Arresters WAN Wide Area Network TO Transmission Owner WEEC Western Electricity Coordinating Council TSO Transmission System Operator B. Summary of Technical Analysis B.1 Existing Smart Grid Roadmap and exchange data by means of a direct link using the Initiatives ICCP protocol. c. Wide Area Monitoring Systems (WAMS) - Pilot Vietnam Electricity (EVN) is partway through the devel- project. The NPT has developed a customized opment of a Smart Grid program, which is aimed at the solution for wide-area measurement that uses integration of a new monitoring, protection and control the synchrophasor functionality. In particular the system for enhancing the electrical network. HMI solution consists of four applications tailored for specific local uses: Running parallel with EVN’s program, the National Power Transmission Corporation (NPT) has accelerated its own i. Desktop application for calculating the real- Smart Grid technology development. The initiatives they time power transfer capability of the system are currently progressing are: and providing alarms based on thresholds set by the user; a. Substation Automation System (SAS). This ini- ii. MATLAB application for migration of synchro- tiative is comprised of three phases. The first two phasor data to a programming environment have already been developed, while the third is for performing complex calculations; ongoing. The three stages deal with: iii. Web application that provides remote access i. Digital protection and control using legacy to the data via a secure Internet connection; serial and hardwired connections, and in par- ticular, problems with interoperability between iv. Office productivity applications that provide multiple manufacturers’ Intelligent Electronic a data-link interface to the plant information Device (IEDs). database. ii. Specifications for SAS aimed at improving IED The broader roadmap includes elements of: compatibility. UCA2, Modbus TCP , DNP TCP and IEC 60870-5-104 were chosen as substa- a. Substation Automation System (SAS) tion LAN communication protocols between upgrade. This initiative addresses the develop- Host Computers and the IEDs or NIM (Net- ment of all the new substations that are going to work Interface Modules). The IEC 60870-5-101 be installed (150 from 2016 to 2030). protocol was chosen for the transfer of data from a substation’s real time database to the b. Communications Infrastructure for Transmis- existing SCADA system. sion and Substations. In order to ensure suffi- cient and appropriate information is available for iii. Installation of digital equipment and the adop- the information systems at NPT’s head-office and tion of the IEC 61850 protocol for LAN com- 04 PTCs, it is necessary to develop the North- munications. The IEC 60870-5-101/104 will be South information backbone and to connect the used instead for communication between the WAN network to all substations under NPT’s SAS and the Remote Centre, i.e. the Informa- management. tion System for Operation and Supervision of the NPT networks. c. Upgrade Information System. The main pur- poses are: b. Information System for Operation and Super- vision. This initiative aims to create an Informa- i. Connecting directly to NPT’s substations for tion Centre to support remote operation of the acquiring data (Analog, Status information substations and the first instance of remote from the substation as well as metering data) operations will be in place by the end of 2015. and providing data to PTC’s Information Sys- The SCADA/EMS System of the NLDC and the tems and data backup for the NLDC’s SCADA Information Systems of the NPT will collect infor- system. mation in parallel from the field and will be able to 7 8 Smart Grid to Enhance Power Transmission in Vietnam ii. Integrating WAMS, DTCR, FLS with NPT’s and i. Dynamic rating and real-time monitoring of PTC’s Information Systems. transmission lines are being perceived as important tools to maintain system reliability iii. Integrating advanced functions such as calcu- while optimizing power flows. lation load flow, stability limit, power capability in real-time (on-line) of transmission network, ii. Dynamic ratings can be considered a low-cost calculation load flow, fault, stability in offline solution to deliver increased transmission mode, etc. These will be integrated for opera- capacity. In fact, dynamic ratings are typically tional purposes as well as for planning the 5% to 25% higher than conventional static implementation of grid optimization, loss ratings. reduction and improving reliability. iii. Application of dynamic ratings can benefit iv. Exchanging information and data with other system operation by increasing power flow parts of the system in Vietnam’s Electricity through the existing transmission corridors Market. with minimal investments. v. Allowing ease of access for NPT and PTC g. Fault locator system (FLS). This project is staff to gather necessary information from already underway and six of the most important anywhere in the electricity network using substations of the 500 kV transmission network Web services subject to security controls con- will be equipped with FLS devices by the begin- sistent with international standards and best ning of 2015. Other fault locators will be installed industry practices. in key substations of the 220 kV network. d. Metering Data Acquisition System. NPT has h. Geographic Information Systems (GIS). The already planned such a project and its purpose NPT considers this application as central to ensur- is to provide accurate and reliable real-time mea- ing the accuracy and efficiency of the Information surement of energy consumption and supply at System for Asset and Outage Management. all network points where energy is purchased or sold. Table 7 provides a summary of the current Smart Grid initiatives that are already in progress under the manage- e. Wide Area Monitoring Systems (WAMS). Only ment of the various agencies of the Vietnamese electric- a few PMUs have been installed so far and the ity authorities. The table highlights the key information WAMS project for the entire 500 kV network is regarding each of them. currently considered as a project with a mid-term time scale and a predicted completion sometime Against this backdrop, the purpose of this document is in 2022. The project aim is to install PMUs in all twofold: 500kV substations under NPT’s management and the expected benefits are: a. To present the international experience of trans- i. Increased system loading while maintaining mission utilities with Smart Grid applications; and adequate stability margins; b. To refine NPT’s Smart Grid roadmap and produce ii. Improvement of operator response time to sys- a new draft version. tem contingencies such as overload conditions, transmission outages, or generator shutdown; B.2 International Experience and iii. The achievement of advance system knowl- Lessons Learned edge with correlated event reporting and real- time system visualization; Developing nations like Vietnam are experiencing rapid iv. The promotion of system-wide data exchange growth resulting in a commensurate expansion and with a standardized synchrophasor data format; enhancement of their energy transmission network. Whilst the electricity authority has taken the initiative v. The validation of planning studies to improve and is already implementing or planning a number of system load balance and station optimization. Smart Grid applications, there is a risk of disconnection f. Dynamic Thermal Circuit Rating (DTCR). The between the somewhat independent initiatives of the key points considered by NPT regarding this ini- various business units that make up the parent organi- tiative are: zation, the EVN. Thus, in order to ensure coordination Volume 1: Technical Analysis 9 TABLE 7  CURRENT SMART GRID INITIATIVES (ON-GOING AND PLANNED) Current Smart Grid Initiative Key information • Initiative has reached the appropriate level for this stage of its development. Substation Automation System (SAS) • 150 new substations will be upgraded and brought on-line between 2016 and 2030. • The first instance of remote operations will be in place by the Information System for Operation and Supervision end of 2015. • Pilot project developed. Wide Area Monitoring Systems (WAMS) • The project aims to install PMUs in all 500kV substations under NPT’s management. Communications Infrastructure for Transmission and • The North-South information backbone planned. Substations • WAN network to all substations under NPT’s management. Upgrade Information Technology System • Enhance interconnection of devices with applications. Metering Data Acquisition System • NPT has already planned such a project. Dynamic Thermal Circuit Rating (DTCR) • NPT is considering such a project for the future. • This project is already underway and six of the most important Fault locator system (FLS) substations of the 500 kV transmission network have had FLS devices installed. • NPT is considering this project as key to the functionality of Geographic Information Systems (GIS) the Information System for Asset and Outage Management. Source: Authors between the efforts of the business units and to maxi- bear some similarity to key issues afflicting Vietnam’s mize the synergy of the applications being deployed as transmission network specifically. well as filling any gaps in functionality the Vietnamese Smart Grid roadmap will need to be refined to include In particular the main issues and challenges identified applications that are not yet integrated within their exist- in the Vietnamese transmission system are: (i) network ing systems. topology issues; (ii) short circuit levels; (iii) miscoordina- tion of protection systems; (iv) defense plan improve- The applications that fill the gaps in functionality are nec- ments; (v) loadfrequency regulation improvements; (vi) essary for the successful implementation of the Smart 500 kV limited transient stability; (vii) voltage stability, Grid at a systemic level. On the basis of international profile and support/reactive power balance; (viii) lightning experiences a wider view has been adopted to include performance of exposed 220 kV lines; (ix) SCADA and some solutions that are not usually considered “smart” . remote-control centers; (x) time and cost reduction of asset maintenance; (xi) power quality; and (xii) intercon- Lessons learned from the international experience with nections with neighboring countries. Smart Grid development were based on the experiences of the Italian, European and American initiatives. These The first international experience presented is that of three cases were selected since they offer a good bench- Terna, the Italian TSO. The analysis of the Italian experi- mark for comparison with existing or planned Vietnam- ence and subsequent initiatives is particularly relevant to ese Smart Grid initiatives in general and because they the Vietnamese experience precisely because the long, 10 Smart Grid to Enhance Power Transmission in Vietnam thin shape of both countries has dictated a very similar in the context of a significant change in the operation of north-south electricity distribution topology with a similar the grid, due to the substantial unbundling of the assets concentration of power plants at the extremities of the of the electrical system further compounded by substan- country. tial energy input from unpredictable renewable sources. The combination of these factors brought about a need The Italian experience is particularly helpful, as some for greater flexibility and a faster response capability in of the Smart Grid applications selected for solving key order to overcome the significant complexities of plan- issues and for developing strategies provide a useful ning and programming the development of the transmis- starting point and context for the solutions proposed sion network on a medium/long term basis. for Vietnam. For example, some parts of the Italian electricity network experienced short circuit levels that The third and final international experience that is ana- exceeded the rated current limit of the circuit breakers, lyzed looks at some key Smart Grid initiatives imple- however these problems were satisfactorily resolved by mented in the USA. Firstly, the American experience developing appropriate Planning and Asset Management with PMU installations and subsequent development of strategies. WAMS applications is very interesting because of their approach, the very high number of applications devel- Further, as in Vietnam, the Italian network topology oped (confirming the potential of WAMS and in particular exposes the system to transient and voltage stability of the exploitation of PMU data) as well as for the results problems. These issues were among the key drivers for obtained. the development the WAMS project. The Italian WAMS experience may prove as useful for Phasor Measure- The sophisticated technological level reached by the ment Unit (PMU) positioning as much as for the kinds of US transmission systems has resulted in the develop- applications developed and the process of progressive ment of some very advanced Smart Grid applications integration of WAMS functions in day-to-day systems like Dynamic Rating. Furthermore, thanks to the large operations. number of ISOs and to their differing breadths of scope, there are lessons to be learned from the very The Italian transmission network experience is also very different responses to the same problems. Towards interesting from the perspective of applications such as this end two dissimilar projects using Dynamic Rating Substation Automation System, Lightning Location Sys- are presented. tem, Power Quality Monitoring and Metering Data Acqui- sition System. The USA transmission system experiences may encour- age the introduction of online sensors to predict trans- Moving from a single country, Italy, to the European former failures (Dissolved Gas-in-oil Analysis - DGA). This electrical infrastructure sets the scene for elaborat- technology is quite widespread but about half of all the ing a broader example of what constitutes appropriate devices worldwide are actually installed in the US net- planning for a large network. The European Commis- works (40,000 of the 80,000 worldwide). A particularly sion’s ENTSOE Ten-Year Network Development Plan instructive incident at BC Hydro is described in order to 2014 brought together leading European TSOs in order understand best practice of this Smart Grid solution. This to establish the guidelines for the development of the may provide a good reference to evaluate the opportunity entire European network. In particular, this plan focused to install sensors for on-line DGA on new and old power on addressing transmission investments starting with transformers. the identification of bottlenecks across Europe. This process could become the basis of best practice in the Another area where new solutions within a transmission future development of interconnections between Viet- network may be of relevance for the Vietnamese grid are nam and its neighboring countries. Moreover, this experi- those related to a new type of application developed for ence highlights the importance of shared N-1 criterion HVDC systems. Direct Current (DC) technology, in fact, assessment in a large interconnected system. has been used to resolve some problems similar to those experienced by the Vietnamese grid where the primary Reactive Power Compensation in the UK, i.e. by the requirement was an increase in the level of transmitted NGC, represents another important European example power to large load areas. Towards this end the TRANS- of best practice. This refers to the approach adopted by BAY project for PG & E in California is discussed. the NGC, to ensure the control and regulation of reactive power exchange and therefore the proper management Table 8 presents a summary of the key lessons learned of the voltage profiles in a transmission system. This was from the international experience. Volume 1: Technical Analysis 11 TABLE 8: KEY LESSONS LEARNED FROM THE INTERNATIONAL EXPERIENCE Country/ Region Initiative Key lessons learned • Some solutions for transmission system • A useful starting point for building the future transmission enhancement network on a solid foundation. • Applications to monitor transient and voltage stability. • WAMS • PMU positioning techniques. • Substation Automation System • Telecommunication system constraints. ITALY • Guideline for LLS installation. • Lightning Location System (LLS) • Benefits for Planning, Asset Management and Operation. • Voltage dips reduction. • Power Quality Monitoring • Identification of protection system malfunctions. • Regulatory implications. • Metering Data Acquisition System • Interface with electricity generation. • Best practice in the future development of interconnections • N-1 criterion assessment between Vietnam and its neighboring countries. EUROPE • Control and regulation of reactive power exchange. • SVC • Management of the voltage profiles. • WAMS • Efficient approach to the definition of an applications roadmap. • Dynamic Thermal Circuit Rating (DTCR) • Different available techniques. USA • On-line Dissolved Gasinoil Analysis (DGA) • Reference to evaluate the opportunity to install sensors for for Power Transformers on-line DGA on new and old power transformers. • Possible solution to increase the level of transmitted power to • HVDC large load areas. Source: Authors B.3 Transmission System c. Load-Frequency Regulation Strategy Improve- Enhancements ments: The aim is to guarantee frequency stabil- ity and transient support by allocating sufficient The second part of this document starts with a gap analy- primary reserve and also an AGC to overcome any sis, which identifies the transmission system enhance- power imbalance due to generation tripping or ments that would enable the successful implementation changes in the imported/exported power levels. of the refined Smart Grid roadmap for NPT. d. Protections System improvements: The aim is to equip substations and transmission lines with This analysis is based on international best practices vis- state of the art digital relays in order to protect à-vis the following pillars: against failures and coordinate their intervention by means of inter-tripping logic systems (when a. Planning and Asset Management System required). basic strategies improvements: The aim is to drive transmission network expansion in order to e. Telecommunication System improvement: overcome present network topology issues. The aim is to support the development of the pre- vious initiatives linked with the data communica- b. State Estimation and on-line N-1 Security tions network. Assessment: The aim is to have proposed on-line solutions for expected contingencies; improve Deployment of transmission system enhancements is the real time knowledge of electrical system sta- envisioned in the very-short term (two to three years). tus and recommend best practice in preventive Figure 4 positions such enhancements on a hypothetical and corrective remedial actions. timeline. 12 FIGURE 4: TIME POSITIONING OF TRANSMISSION SYSTEM ENHANCEMENT INTERVENTIONS Smart Grid to Enhance Power Transmission in Vietnam Source: Authors Volume 1: Technical Analysis 13 These interventions are detailed in the document and Such time positioning is complemented by a general as they do not require any preliminary activity they can estimation of associated costs, based on the informa- start immediately. The proposed elapsed time of the tion gathered and assumptions made about the Vietnam implementation process for the different interventions is transmission system. Such cost estimates are captured a conservative estimation, based on similar activities per- in Table 9. It is worth underlining that for some initia- formed in other countries (e.g. Italy). It could happen that tives no costs are needed. In such cases, the proposed such elapsed times will be lower than predicted due to enhancements do not require real investments, but some analogous initiatives already planned or underway. rather imply an improvement in the current practice to exploit existing resources more efficiently. TABLE 9: COST ESTIMATES FOR TRANSMISSION SYSTEM ENHANCEMENT INTERVENTIONS (SOURCE: AUTHORS) PILLAR INTERVENTION COST ESTIMATION Negligible in the context of the initiatives already Implement local automation strategy in underway for setting-up substation automation stations with three autotransformers systems. Verify the design of neutral reactance in Negligible in the context of the current work in substations where a high percentage of Planning and Asset progress on network maintenance activities. unsuccessful single pole reclosing occurs Management System basic strategies improvements The swapping of 30 breakers (at critical points) at Complete the substitutions of all the a cost of $10,000 each results in a total spend of breakers in most critical areas $300,000. Complete the installation of reactors The installation of 20 reactors at a cost of $40,000 between busbars in critical areas each results in a total cost of $800,000. Complete roll-out of State Estimation Negligible in the context of the initiatives already algorithm underway for setting-up a new EMS system. Complete roll-out of N-1 Security Negligible in the context of the current work in Assessment procedure progress on setting-up a new EMS system. State Estimation and on-line N-1 Security Assessment Complete automation of State Estimation Total cost of $300,000 considering both software algorithm and on-line N-1 Security purchase and operator training program. Assessment procedure Complete roll-out of Dynamic Security Total cost of $300,000 considering both software simulation purchase and operator training program. Analysis of the primary Load-Frequency Total cost of this survey activity is estimated at Regulation of the system considering the $200,000. best set of power units to be involved Load-Frequency Regulation Complete roll-out of primary Load- For hardware and software installation the expense strategies improvements Frequency Regulation can vary from $30,000 to $60,000 for each power plant. Assuming installation in 40 power plants, Complete roll-out of secondary Load- the total cost would be between $1,200,000 and Frequency Regulation $2,400,000. (Continued next page) 14 Smart Grid to Enhance Power Transmission in Vietnam TABLE 9 (CONTINUED) PILLAR INTERVENTION COST ESTIMATION Complete a detailed survey of all installed Negligible in the context of the current work in protection systems progress on maintenance activities. Development of an installation strategy that Installing dual protection on 30% of lines at an could allow a consistent and incremental average cost of $5,000 each results in a total cost improvement of system reliability of $1,500,000. Protections System improvements Repairing 5% of protection systems at an average cost of $3,000 each results in a total cost of about Complete the interventions to either $150,000 repair or replace unsuitable or damaged protections Replacing 5% of protection systems at a cost of $5,000 each results in a total cost of $250,000. Support to provide inputs for SCADA State Estimation Negligible in the context of the current work in TLC system improvements progress on setting-up the telecommunication Support to provide inputs for Load- infrastructure. Frequency Regulation Source: Authors B.4 Problems-Solutions Mapping a. Fault Locator System (FLS). A NPT project is already underway and is quite independent from After identifying transmission system enhancements, all the other initiatives. It can contribute to time an exercise on mapping problems to solutions was car- and cost reduction of asset maintenance of the ried out. This resulted in mapping Vietnam’s network most critical areas of the network with a relatively issues and challenges—which are discussed at length in few number of components. In order to evaluate Annex 2—to the above-mentioned pillars, and ultimately the success of the FLS initiative, it will be neces- to the Smart Grid solutions considered as viable for Viet- sary to measure the reduction in the time it takes nam and proposed in the refined NPT Smart Grid roadmap. for a maintenance crew to attend the fault loca- tion and the related outage duration (i.e. Mean A summary of the issues-solutions mapping and chal- Time to Repair). The FLS application can be con- lenges-solutions mapping is offered in Table 10 and Table sidered satisfactory if after its implementation 11 respectively. It is worth noting that in some cases the such times are reduced by 25%. simple “pillar” implementation is required, while in oth- b. Wide Area Monitoring System (WAMS). ers only a Smart Grid initiative can solve the problem. Besides the fact that NPT has developed a pilot project, WAMS is a solution that could impact many of the other applications (e.g. Dynamic B.5 Technical Prioritization and Thermal Circuit Rating) and aims to solve a large Revised Smart Grid Roadmap number of issues (e.g. voltage and transient stability, defense plans improvements, etc.). The solutions identified for the NPT Smart Grid roadmap The main items in relation to WAMS that are have been prioritized according to three time horizons: addressed in this document are: the short term (within the next 5 years), the medium i. The PMU positioning strategy emphasizing term (within the next 10 years) and the long term (within the importance of monitoring not only the 500 the next 15 years). KV network but also the 220KV network; Short-term Smart Grid solutions include: ii. A brief description of possible WAMS applica- tions useful for the Vietnamese context such Volume 1: Technical Analysis 15 TABLE 10: ISSUES-SOLUTIONS MAPPING ISSUES ISSUES CHARACTERISTICS PILLARS SMART GRID SOLUTIONS • Planning and Asset Network topology • Static Var Compensators • Network highly meshed Management strategies issues • Dynamic Thermal Line Rating improvements • Planning and Asset • Fault current could exceed the rated Short Circuit Level Management strategies • Not Applicable current of the breakers improvements • Outages due to protection failures Miscoordination of • Interference and electro-magnetic • Protection System • Power quality monitoring Protection System compatibility issues on secondary improvement system signals • If the N-1 security criterion is not fulfilled and SPS remedial action is • State Estimation • Substation Automation System Defense Plan necessary • N-1 on-line Security • Wide Area Monitoring improvements • The security assessment is performed assessment Systems on desk (not on-line) • Presently this type of regulation is • Load-Frequency regulation LoadFrequency achieved by using one hydro power strategies improvements • Not Applicable regulation plant at a time from a maximum of five (AGC) • State Estimation 500kV limited • Wide Area Monitoring • High North–South power flow • N-1 on-line Security transient stability Systems assessment Voltage Stability, Profile • State Estimation • Wide Area Monitoring and Support/Reactive • High North–South power flow • N-1 on-line Security Systems Power Balance assessment • Static Var Compensators Lightning Performance • Surge Line Arrester installation without • Not Applicable • Lightning Location System of exposed lines a Lightning Location System Source: Authors TABLE 11: CHALLENGE-SOLUTIONS MAPPING CHALLENGES CHALLENGES CHARACTERISTICS PILLARS SMART GRID SOLUTIONS • Substation Automation System • Wide Area Monitoring Systems Monitoring and • Improve the monitoring, • Telecommunication system • Metering Data Acquisition System remotely control observability and control of the improvements • Geographic Information Systems the network network • On-line Dissolved Gasinoil Analysis for Power Transformers Time and cost • Improve the efficiency of the reduction of asset • Not Applicable • Fault Locator System system maintenance • Improve the quality of the Power Quality • Not Applicable • Power quality monitoring system system • State Estimation • Interconnections with • N-1 on-line Security assessment • High Voltage Direct Current Interconnections neighboring countries • Load-Frequency regulation technology strategies improvements Source: Authors 16 Smart Grid to Enhance Power Transmission in Vietnam as voltage stability monitoring and oscillation d. Lighting Location System. This is considered detection and monitoring. as a short-term solution due to the criticality of the lightning problem and the significant number Evaluating the success of the WAMS initiative of transient faults incurred on the Vietnamese is very complex and it is strictly dependent on electricity network. Further, the installation of a the ancillary functions developed using PMU Lighting Location System requires quite a long data. For example, a voltage stability monitoring lead time which is why, if the proposed solution is feature based on WAMS can be considered suc- approved by NPT, it should begin as soon as pos- cessful if it helps to prevent 15%-35% of volt- sible. Towards this end, this document presents a age collapses. The percentage depends on the guideline for the development of such a system, topology of the portion of the network involved in highlighting the benefits with a particular focus the voltage instability event. Equally, a transient on the installation of Transmission Surge Line stability monitoring function on WAMS can be Arresters. After the installation of Transmission considered successful if it helps to prevent 15%- Surge Line Arresters (guided by Lighting Location 35% of power plants falling out-of-step. As with System data analysis) the percentage reduction the voltage collapse example, the actual percent- of transient faults can be used as a KPI where a age depends on the topology of the portion of the reduction in the range of 20%-30% can be con- network involved. sidered satisfactory. c. Substation Automation System (SAS) (includ- e. Metering Data Acquisition System. The NPT ing building/upgrade of substations and project is already underway and it is important building of Remote Control Centers). This is a to reach a full rollout of this initiative in the near NPT project that has already reached a significant future because it represents the enabling tech- level of development. It has been conducted in nology for the development of the electricity synergy with building of Remote Control Cen- trading market. The simultaneous installation of ters for unmanned substations since Remote SAS may be useful for facilitating the data acqui- Control Centers constitute a pre-requisite to sition process of the Metering Data Acquisition exploit at best SAS equipment in electrical sub- System. It is worth to consider that for the full stations. Their realization is fundamental to posi- deployment of such initiative a careful investiga- tion such SAS initiative in the short term. In order tion of all the regulatory aspects is fundamental. to support remote control the development of a To evaluate the success of the Metering Data communication backbone connecting all the sub- Acquisition System initiative it is worth measur- stations under NPT management is a fundamen- ing the mean square error between the value tal requirement. The status of the deployment to acquired by the meters and the value calculated date is discussed and some recommendations by the settlement for the same meter. A satisfac- are made in order to optimize the benefits of tory value would lie in the range 0.4%-0.8%. this solution, especially with regard to interoper- ability and pre-requisite telecommunication sys- f. On-line Dissolved Gas-in-oil Analysis. It is tem improvements. Fully digitalized substations, proposed that all new transformers have this remote terminal units, remote operation and device installed, as its cost is low in comparison supervision represent the key elements for the with value of the transformer it protects and no success of SAS initiative. The Key Performance particular analysis has to be performed before Indicator (KPI) for judging the success of this installing this equipment on new transformers application is the reduction of Energy Not Served (as mentioned in paragraph ‘F .11’). Furthermore, (ENS). It can be considered successful if after NPT has already started to develop this initiative SAS implementation the average value of faults and it is worth to continue investing in this type prevented per year, per substation equipped of technology on all the transformers that will be with SAS is above 1.5. Given the average value installed in Vietnam in the next years. Therefore of 300  MWh of load losses per fault event, the this initiative has been positioned in the short value of 1.5 corresponds to an average ENS term. On the other hand, their use with the exist- reduction of 450 MWh per year for each substa- ing transformer fleet instead will require the iden- tion equipped with SAS. tification of the most critical and valuable ones Volume 1: Technical Analysis 17 that need to be protected. In fact equipping cur- initiative. In order to evaluate the success of the rent transformers with these monitoring devices GIS initiative, it is worth measuring the reduction requires a detailed investigation in order to evalu- in the management costs of the network. A cost ate the time needed to gather data for the char- reduction of 10%–15% can be considered a sat- acterization of typical transformer behavior so as isfactory result. to eliminate false positives. The DGA installation c. Power quality monitoring system. Power Qual- initiative can be considered successful if using ity is one of the challenges of the Vietnamese these monitoring systems a consistent preven- transmission system but it is not considered as tion of transformer outages is achieved. A satis- one of the most critical. The benefit of this type factory value is a reduction by 80% in the number of system can best be judged by the extent to of faults. which it improves power quality levels. This in Medium-term interventions include: turn helps to optimize investments in installations aimed at increasing resilience to voltage dips and a. Static Var Compensator (SVC). The main ben- increasing the ability to promptly identify mal- efits of this type of system are related to possible functioning protection systems. A suitable KPI is applications within the Vietnamese transmission the percentage reduction of voltage dips where a grid. SVC systems help to regulate the voltage value above 20% can be considered satisfactory. profile of the 500 kV transmission lines and, with Long-term Smart Grid applications include: suitable control loops properly integrated with the WAMS applications, to significantly increase a. High Voltage Direct Current (HVDC) technol- the damping of the system during transients ogy. The technical and economic benefits that particularly in cases of inter-area oscillation. It can be achieved are specific to niche applications, is important to highlight that before installing such as interconnections with neighboring coun- SVCs a very detailed feasibility study has to be tries or reinforcing the north-south backbone with performed. Making the right choice of locations high power flows or supplying large congested for SVC devices in the fast growing Vietnamese loading areas that have high levels of short cir- network will prove to be exceptionally challeng- cuit currents and loop-flow issues. However, this ing. Towards this end, the use of re-locatable SVC topic is not a priority and HVDC represents one systems is recommended as a possible solution of several solutions that are worth evaluating. The to ensure maximum flexibility for this kind of success of an HVDC link is measured by its load application in the light of the rapid development factor where a value above 0.7 can be considered of the transmission system and the need to pro- satisfactory. vide timely support for substantial changes and reconfigurations of the grid. The success of a SVC b. Dynamic Thermal Circuit Rating (DTCR). This installation can best be judged by measuring the document presents the main techniques used for voltage level variations of the most important net- implementing this Smart Grid solution. The steps work nodes (named “pilot nodes”). If 95% (1 σ) required to develop a DTCR project that uses all of such variations are within +/-5% of the rated the different techniques are also proposed. NPT voltage the result can be considered satisfactory. has already planned the development of such an Furthermore, as for WAMS evaluation, a SVC can application, so the implementation of a pilot proj- be considered to be operating successfully if it ect will be a good starting point. On the other helps to prevent 15%-35% of voltage collapses hand, it would be better to wait for the current in the portion of the network influenced by such rapid growth rate of the transmission network to events. stabilize in order to leverage this application on a large scale. According to international experi- b. Geographic Information Systems (GIS). This ence the dynamic ratings are typically 5% to 25% cannot be considered as a single Smart Grid ini- higher than conventional static ratings. The imple- tiative in its own right but needs to be seen as mentation of DLR will be considered satisfactory a means of enabling other applications. The prior if on the lines where it is applied the “ampacity” development of other systems like SAS or WAMS increases from 5% to 25%. could be very useful to plan the implementation of this type of solution to ensure that the largest Expanding on the concept of “pillars” , the technical priori- possible number of applications benefit from this tization led to the refined Smart Grid roadmap (figure 5). 18 FIGURE 5: TECHNICAL PRIORITIZATION AND REFINED SMART GRID ROADMAP Smart Grid to Enhance Power Transmission in Vietnam Source: Authors Volume 1: Technical Analysis 19 The technical approach used to prioritize the Smart Grid The refined NPT Smart Grid roadmap will be finalized applications is a good starting point for the design of a upon completion of the following: (i) application-specific phased roadmap, but it is not exhaustive. Further, some cost-benefit and risk analyses; (ii) observations related metrics for the evaluation of the success of the various to aspects of regulation, performance monitoring and Smart Grid solutions are proposed and summarized in implementation strategy. This work will be the focus of the following Table 12. the next two reports accompanying this document. TABLE 12: TECHNICAL METRICS IDENTIFIED FOR SMART GRID SOLUTIONS SMART GRID SOLUTION PERFORMANCE INDICATOR SATISFACTORY THRESHOLD Reduction of time taken to attend fault site by Fault Locator System 25% maintenance crew and related outage duration Voltage collapse prevention 15%-35% Wide Area Monitoring System Out-of-steps prevention 15%-35% Energy Not Served (ENS) reduction per year for each Substation Automation System 450 MWh substation equipped with SAS Lightning Location System Percentage reduction of transient faults affecting the lines 20%-30% Mean square error between the value acquired by the Metering Data Acquisition System meters and the calculation by the settlement process for 0.4%-0.8% the same meters 95% (1 σ) variation interval of voltage level of network +/-5% of the rated voltage “pilot nodes” Static Var Compensator Voltage collapse prevention 15%-35% Geographic Information Systems Reduction of management costs 10%-15% Power quality monitoring system Percentage reduction of voltage dips 20% High Voltage Direct Current technology Load factor 0.7 On-line Dissolved Gasinoil Analysis Reduction in the number of faults 80% Dynamic Thermal Circuit Rating “Ampacity” increase 5%-25% Source: Authors C. Introduction C.1 General Overview The first objective of this document is to review inter- national best practices that have helped to solve issues This document presents a technical analysis and devel- similar to the ones identified in the Vietnamese transmis- ops key elements identified in the Inception Report in sion network and, on this basis, to propose candidate order to design the Smart Grid Roadmap for Vietnam. The Smart Grid Applications and/or technology in order to general overview of the approach followed in this analy- address such problems. sis is depicted in Figure 6 below. Smart Grid roadmaps articulated at an international level During the initial discovery process the issues and the for mature networks may provide good benchmarks and challenges regarding the electrical network, together useful examples in order to effectively plan the Smart with all the information collected, were collated and stud- Grid implementation for Vietnam while keeping in mind, ied in order to define the problems that needed analysis as already stated, that this approach may need some and investigation. refining. In this scenario the development of some appli- cations and technologies will be considered as the funda- The vision of the proposed Roadmap, as presented in mental basis for the subsequent implementation of more Figure 7, starts from these issues and identifies the pos- advanced applications. sible Smart Grid Applications and Smart Grid devices that may help to resolve the identified problems. FIGURE 6: GENERAL OVERVIEW OF THE APPROACH Source: Authors 20 Volume 1: Technical Analysis 21 FIGURE 7: VISION OF THE ROADMAP Source: Authors For this reason the methodology for developing a Smart C.2 Structure of the Document Grid roadmap will firstly define a number of essential concepts (e.g. state estimation, security assessment, This report is split into two main parts. The first part is remote control and regulation, asset monitoring and composed of chapter ‘D’ while the second part is com- management) as the necessary “pillars” that will form prised of three sections (‘E’ to ‘G’). the ideal foundation for the creation of a smart network. The first part of this document (chapter ‘D’) addresses The aim is to define a common shared vision of compo- the identification of those international best practices nents and equipment for the Smart Grid development in and experiences of Smart Grid technologies that are Vietnam starting with the current operating model and applicable to the current Vietnamese situation and those the forecasted status of the electricity sector. that will help to develop their longer term roadmap. The Smart Grid initiatives must be tailored to fit the spe- For the introduction of the Smart Grid solutions in the cific needs of Vietnam, taking account of not only the Vietnamese context refer to ‘Annex 1’ and ’Annex 2 ‘. best practices and experiences, but also the current Viet- They respectively deal with: namese state-of-the-art Smart Grids projects as these will be the basis for developing an integrated roadmap a. The definition of best practices based on the specifically for Vietnam. This will be focused in the short- experiences of electricity transmission system term on those initiatives that can be achieved quickly and functions and owners from around the world. consistently with the existing and approved on-going This view also defines the key players that have initiatives and, in the medium/long-term, on those initia- been involved and instrumental in the evolution tives that will require a longer development cycle. of Smart Grid technologies to the present day. 22 Smart Grid to Enhance Power Transmission in Vietnam b. A brief description of the current operating model Grid technologies across the Vietnamese trans- of the Vietnamese electricity sector with a par- mission systems, operators and functions. This ticular focus on the current challenges and issues prioritization is mindful of achieving the quick faced by the Vietnamese electricity transmission wins as promptly as possible whilst preparing operators. the infrastructure and the operators for the short to medium term and the medium to long-term The second part of this document (‘E’ to ‘G’) examines initiatives. three specific aspects: In addition to the approach outlined briefly above, the a. The identification of those Smart Grid solutions Consultant also aims to leverage his own experience and suitable and applicable to the Vietnamese con- expertise to identify those areas of further development text. The aim here is to map the Vietnamese and opportunity that have not been identified yet by the issues and challenges to the proposed Smart Vietnamese operators, technicians and other experts that Grid initiatives. briefed the consultant during the discovery processes. b. A detailed examination of the proposed solu- As part of this work the Consultant will also identify the tions introduced in the preceding point above means of measurement as well as the most relevant (46.a). The proposed solutions are a combination metrics to ensure the achievement of global policy tar- of technology (typically Smart Grid applications gets such as e.g. the overall reduction of faults, short and infrastructures), processes, procedures and circuit events etc. across the electrical infrastructure as commensurate training. This section emphasizes a whole. The parameters identified through the process the need to ensure that the pre-requisite infra- of measurement will be tied to global policy targets (Key structure and training are both already in place to Performance Indicators) in the sector [1]. leverage the benefits of this combination of new technologies and processes. All of these steps will aim to delineate the vision and c. A prioritization of technical and process devel- objectives of NPT’s Smart Grid roadmap [2] and to define opments to enable the integration of the Smart a technically driven phased implementation plan. D. Relevant International Experiences of Smart Grids for Transmission Systems D.1 Key Points Summary of broader example of what constitutes appropriate plan- International Experiences ning for a large network. The European Commission’s ENTSO–E Ten-Year Network Development Plan 2014 This chapter is focused on presenting those examples [3] brought together leading European TSOs in order of Smart Grid technologies from transmission utilities to establish the guidelines for the development of the around the world that are most relevant for the Vietnam- Europe-wide network. In particular, this plan focused on ese network. These examples have been chosen on the addressing transmission investments starting with the basis of the applied design methods and for the types of identification of bottlenecks across Europe. This process problems they aimed to resolve as well as for the imple- could become the basis of best practices in the future mented solutions many of which are appropriate and rel- development of interconnections between Vietnam and evant to the Vietnamese scenario. its neighboring countries. Moreover, this experience highlights the importance of shared N-1 criterion assess- The first international experience presented is that of ment in a large interconnected system. Terna, the Italian TSO. The analysis of the Italian experi- ence and subsequent initiatives is particularly relevant to Another important European example of best practice the Vietnamese experience precisely because the long, is represented by Reactive Power Compensation in the thin shape of both countries has dictated a very similar UK, i.e. NGC (National Grid Company). This refers to the north-south electricity distribution topology with a similar approach adopted by NGC, to ensure the control and reg- concentration of power plants at the extremities of the ulation of reactive power exchange leading to the proper country. management of the voltage profiles in a transmission system. This was in the context of a significant change in The following sections discuss some basic applications the operation of the grid due to the substantial unbundling and strategies exploited in the Italian transmission sys- of the assets of the electrical system further compounded tem in order to provide a useful starting point and con- by substantial energy input from unpredictable renewable text for the proposed solutions for Vietnam. For example, sources. The combination of these factors brought about some parts of the Italian electricity network experienced the need for greater flexibility and a faster response capa- short circuit levels that exceeded the rated current limit bility in order to overcome the significant complexities of of the circuit breakers, however these problems were planning and programming the development of the trans- satisfactorily resolved by developing appropriate Plan- mission network on a medium/long term basis. ning and Asset Management tactics and strategies. The third and final international experience that is ana- Further, as in Vietnam, the Italian network topology lyzed below looks at some key Smart Grid initiatives exposes the power system to transient and voltage implemented in the USA. Firstly, the USA experience stability problems. These issues, in the Italian network, with PMU installations and subsequent development of were the key drivers for the development of projects like WAMS applications is very interesting because of their WAMS. The Italian WAMS experience may prove very approach, the very high number of applications devel- useful for the positioning of Phasor Measurement Units oped (confirming the potential of WAMS and in particular (PMU) as well as for the kinds of applications developed of the exploitation of PMU data) as well as for the results and the process of progressive integration of WAMS obtained. functions in System Operations. The sophisticated technological level reached by the The Italian transmission network experience is also very US transmission systems has resulted in the develop- instructive from the perspective of applications such as ment of some very advanced Smart Grid applications like SAS, Lightning Location System, Power Quality Monitor- Dynamic Rating. Furthermore, thanks to the large num- ing and Metering Data Acquisition System. ber of ISOs and to their differing breadths of scope, there are lessons to be learned from very different responses Moving from a single country, Italy, to the European to the same problems. Towards this end two dissimilar electrical infrastructure sets the scene for elaborating a projects using Dynamic Rating are presented. 23 24 Smart Grid to Enhance Power Transmission in Vietnam The USA transmission system experiences may encour- was in charge of dispatching generation and operating age the introduction of online sensors to predict trans- the HV Grid. former failures (Dissolved Gas-in-oil Analysis - DGA). This technology is quite widespread but the majority of all the The initial consequence of this split, in what had once devices worldwide are actually present in the US net- been a single role now covered by GRTN and Terna, was works (40,000 of the 80,000 worldwide). A particularly the separation and demarcation between grid planning instructive incident at BC Hydro will be described in order and operational functions. The first was the responsibility to understand best practice of this Smart Grid solution. of Terna, which was the TO of the Italian network but not This may provide a good reference to evaluate the ben- the System Operator. The latter was the responsibility of efit of installing sensors for on-line DGA on new and old GRTN who had the experience and the ability to address power transformers. system bottlenecks and implement the most effective remedies. Another area where new solutions within a transmission network may be of relevance for the Vietnamese grid are This dichotomy was apparent in the operational proce- those related to a new type of application developed for dures. The agreement between the two entities stated HVDC systems. Direct Current (DC) technology, in fact, that if a GRTN Control Room Operator needed to switch has been used to resolve some problems similar to those a line, they were required to ask Terna’s Control Centers experienced by the Vietnamese grid where the primary to open the circuit breakers. requirement was an increase in the level of transmitted power to large load areas. Towards this end the TRANS- This strict separation of roles between the two entities BAY project for PG&E in California is discussed. had some very serious implications. Every modification or enhancement to the grid (e.g. construction of a new line or installation of a key device) should have been D.2 Italy driven by, or at least have taken into account, GRTN’s recommendations on the most effective solution and the The primary relevance of the Italian experience to the most ideal location of its application. In some cases the situation in Vietnam is that prior to 2005 the structures of risk of grid planning strategies diverging from operational their Transmission Utilities were very similar. This is why needs has been significant. This failing was becoming it is important to highlight the structural composition, to ever more apparent to the Italian government who had underline the criticalities for the former and to describe begun to reconsider the organizational structure of their the reasons for the evolution to the current Italian elec- electricity grid operators. It was against this background tricity transmission system organization. that the 2003 blackout gave this evolutionary process a greater impetus, because it highlighted how the Elec- The next few paragraphs present some aspects of the trical Grid was, and will always remain, a vital strategic Italian experience for the following reasons: asset for any sovereign nation. Towards this end a more robust and controllable grid management policy was a. To introduce best practice for the development of deemed necessary. a Smart Grid; Thus, in 2005 GRTN and Terna merged together into a b. To describe some useful Smart Grid initiatives. single company under the name of Terna S.p.A. The main driver for the change was political and aimed for compli- D.2.1 Italian Transmission System ance with the international experience of Transmission Organizational Structure Experience Utility organizational structures. In fact, in most countries where there was only one Owner of the network, the As a result of the “Decreto Bersani” Act in 1999 the for- same agency was also the System Operator (single TSO mer Italian ISO, ENEL, was unbundled and privatized. The instead of TO + SO). unbundling process resulted in three new companies, viz: ENEL Distribuzione, owner and operator of the dis- In a country where the transmission utility has an organi- tribution network; ENEL Produzione, owner of the power zational structure composed of a full-service TSO the role plants; Terna, Transmission Owner (see Figure 73) below. of an independent authority is fundamental to insure the operating transparency of the organization tasked with Since Terna was only a TO Utility, the role of operating the all the relevant functions and for simulating a competitive Grid was entrusted to a System Operator called GRTN marketplace to ensure a fair, equitable and equal oppor- (“Gestore della Rete di Trasmissione Nazionale”). GRTN tunity tariff system for consumers. Volume 1: Technical Analysis 25 The Italian Authority for Electricity, Gas and Water is an The most critical devices in substations, from a mechani- independent entity tasked with ensuring competitive cal point of view, are the breakers as in most cases bus- market pricing, cost efficient and balanced distribution bars and bays are designed to withstand higher stresses. of services across the country, ensuring equal access to Even if this were not the case, small and cheap mechani- all citizens, as well as enforcing adequate quality levels, cal provisions applied to busbars and bays can easily through regulation and supervisory activities. The Author- enhance their resilience to dynamic stresses caused by ity acts as a consultant for the Italian Government provid- short circuit currents. ing recommendations or submitting proposals on future development of the Electrical, Gas and Water services. Thus, Terna’s planning function decided on a direct swap The Authority acts with complete autonomy and inde- between the new substations and the existing ones by pendence within the context of general political guide- installing the old breakers of those substations experi- lines mandated by the Government and Parliament, and encing high short circuit levels in the new substations which are consistent with the regulatory framework of and installing the new breakers in the old substations. the European Union. The excellent working relationship between System Operation and Asset Management facilitated this swap, Among all the various functions addressed it is worth as it was well understood that the breakers from the old highlighting that the Authority: substations whilst older than the new ones, were more than capable of handling the short circuit current levels a. Defines fees for the use of the various utility experienced in the new substation areas. infrastructures; The cost of the operation was very low because no new b. Promotes, through its regulatory activities, the devices were required and it only took a short time to investments related to adequacy, efficiency and effect the substitutions. reliability of the services; c. Ensures the openness and transparency of the Furthermore, in order to solve some specific issues service; and related to the short circuit currents exceeding the thresh- old of the equipment, Terna researched the installation d. Is in charge of monitoring, supervision and con- of reactors between busbars (acting as a bus coupler) trol in cooperation with other public supervisory and specified all the associated equipment (the reactor bodies. itself, breakers, etc.). Such reactors can be equipped with a bypass breaker in order to switch it on or off depend- D.2.2 Planning and Asset Management ing on the dispatching condition of the system (i.e. short The short circuit level is one of the issues that involves circuit power and load flow). more than one function of a transmission utility’s orga- nizational structure, in particular Planning, System D.2.3 State Estimation and Security Operation and Asset Management (grid constructor and maintainer). In fact, if the Planning function has to con- Assessment sider fault current level in projecting future devices instal- The on-line State Estimation algorithm computes a com- lation (line, stations, etc.), it is without doubt that a good plete description of the Grid operating point for every working relationship between Asset Management and minute, with an external output every fifteen minutes. System Operation functions, together with the ability to The State Estimation has two main features: make tactical decisions, can provide prompt, timely and cost effective solutions to problems. a. The topology processor; and During the last few years the Italian transmission sys- b. The Least Squares solver. tem dealt with high short circuit levels. In some portions The topology processor checks the accuracy of the of the network the fault current was tending to become SCADA measurement for each busbar section of every too high for the rated current of the circuit breakers. Dur- substation. The main objective of the Topology Proces- ing this period new substations were planned for areas sor is to detect and correct any kind of inconsistency where the short circuit level was much lower whilst the between powers levels, currents and all other floating val- breakers for these substations were rated for much ues measurements and the opening state of the break- higher current levels than those parts of the network that ers (Boolean values). The congruency check is based on were experiencing high short circuit levels. the power balance of the busbar section where the sum 26 Smart Grid to Enhance Power Transmission in Vietnam of all power flows and all power injections at the busbar D.2.4 Defense Plan should always be zero. When this power balance is not The Italian Defense Plan is based on different counter- met the Topology processor changes the opening state measures both automatically triggered and manually of circuit breakers, or stops the power flows on certain issued by Control Operators. The automatic defense line/transformer bays, to restore the busbar balance. actions are under frequency/under voltage load shed- ding, Special Protection Schemes acting on generation Once the Topology Processor has corrected all the topol- and controlled islanding of small portions of the power ogy/measurement mismatches in the substations, the system. Manual defense actions range from the inser- Least Squares solver computes the power system snap- tion of shunt compensation devices, shedding interrupt- shot using a weighted least squares algorithm. The solver ible loads (called “Banco Manovra Interrompibili—BMI”) minimizes the sum of the squared deviation between and emergency load shedding (called “Banco Manovra the estimated values and the measured ones, weighted Emergenza—BME”) consoles. proportionally for the inverse of the quality code of each measure. If the Italian power system experiences a very severe transient current, with a strong imbalance between gen- The Security Assessment is automatically run every fif- eration and power consumption, the frequency drop teen minutes, when a new State Estimation snapshot is cannot be stopped by the primary load-frequency regu- available for third party applications within Terna’s EMS. lation or any other automatic countermeasure. To keep The Security Assessment is divided into two main tasks: the frequency within a range where the system remains controllable by the Control Operators (that is to say with a. Steady State Security Assessment; and a frequency drop less than 5% of the nominal value) b. Dynamic Security Assessment Terna has rolled out more than one thousand under fre- quency load shedding relays. The overall load shedding The Steady State Security Assessment ensures that amount is about 60% of the power consumption of the the system is fulfilling the N-1 security criterion. The entire Italian grid. Each under frequency relay is triggered contingency list applied in the assessment ranges from by frequency thresholds, whose number may change line  /  generation tripping, combined cycle power plant according to the region where the device is installed, and outage and Special Protection Schemes interventions. are fed with both the frequency absolute value and its The N-1 security assessment is run on the most recent first derivative (rate of frequency drop). Terna also rolled grid snapshot, coming from the State Estimation, and on out under voltage load shedding relays to counteract fast a very short term forecast (next 15 minutes) of the grid. voltage drops due to unexpected load increase especially The very short term N-1 security assessment is a crucial from reactive power greater than the primary voltage part of a near realtime Security Constrained Generation regulation capability or strong overloads on transmis- Balancing, where an OPF algorithm dispatches the gen- sion lines. Under voltage relays are triggered by voltage erating units to avoid overloading even for events cov- thresholds and are usually deployed together with under ered by the N-1 contingency list. frequency ones as one single device. The Dynamic Security Assessment ensures the grid’s Some portions of the Italian grid have a physical structure ability to overcome critical contingencies (e.g. N-k or that imposes limitations on power transfer, often referred North Border disconnection) that could lead to huge tran- to as “Critical Sections” or simply bottlenecks (see also sient currents and electricity black outs should a planned paragraph ‘D.3.1.4’). To avoid bottlenecks, counteract countermeasure fail. The DSA procedure is automatically overloads on those transmission corridors and to prevent triggered after every output of the State Estimation and heavy re-synchronization transients Terna has designed checks the systems dynamic behavior against a num- a number of Special Protection Schemes. These SPSs ber of contingencies defined by Control Operators. Shift are usually triggered by the trip of one, sometimes operators can configure and schedule in DSA whatever two or more, circuits of the bottleneck section and are simulation they wish, from simple line tripping to bus- generally designed to trip or reduce the power output bar short circuit or Border disconnection and islanding of production power plants near the tripped circuit. The from the ENTSO-E grid. The DSA procedure sources its trigger comes from a very large range of often complex data from the most recently updated models of genera- activation logics but most of them are driven by sensi- tor controllers (prime movers, AVR, PSS, etc.) and of the tivity coefficients. The SPS trips or reduces generations Defense Plan (see paragraph ‘D.2.4’). at power plants where greater reductions of the power Volume 1: Technical Analysis 27 flows on the remaining (untripped) circuits of the bottle- allocated at each generating unit for secondary load-fre- necks can be achieved. quency control is referred to as the Secondary Regula- tion Reserve. The BMI and BME load shedding consoles are manually tripping actions of load and are available to Control Room Unlike Primary and Secondary control, the Tertiary Load Operators when no other automatic defense counter- Frequency Regulation is a manual control process. As measure would restore the safe operation of the power the Secondary Load-Frequency control increases the system. The BMI console allows Operators to trip spe- power output of each generating unit, the secondary cial interruptible load, such as industrial environments power reserve is consumed. Control Room Operators where signed agreements exist allowing for such actions may restore the secondary reserve by sending to genera- in case of emergency. This contract states the fee that tors, even if they are not participating in the Secondary Terna pays to this industrial consumer for the interrupt- Load-Frequency control, new dispatching provisions, e.g. ible service offered. The BME is an extreme emergency switching on spare generating units or new set-points for load shedding console where operators can shed load operating ones. from the whole power system in order to achieve a gen- eral reduction of power consumption. D.2.6 Automation and Tele-Control for Substations D.2.5 Load-Frequency regulation In 2006 Terna started a SAS project to substitute the old The Italian TSO, Terna, has a hierarchical Load-Frequency wired logic with a new hardware and software architec- regulation, organized in three different control loops: (i) ture that was consistent with the most relevant interna- Primary; (ii) Secondary; and (iii) Tertiary Load-Frequency tional standards. Regulations. Each loop acts on different time frames and serves different network objectives. In particular, IEC 61850 was assumed as a base reference for the allocation of functions and communications, whilst The Primary Regulation counteracts any generation-load the communication with the remote center is performed imbalances due to contingencies and prevents the fre- using IEC 60870-5-101/104. This protocol selection is a quency drop increasing. The Italian Grid Code prescribes shared best practice in a SAS project implementation. that every Production Unit with an “Efficient Power” of at least 10 MW will be party to the Primary Load-Fre- IEC 60870-5-104 is definitely preferable with respect to quency Regulation. The Code defines a Production Unit IEC 60870-5-101 as it is more flexible and easier to re- as any kind of generating unit, regardless of the energy configure when a system upgrade is needed. The exis- source (e.g. Thermal, Hydro, CCPP or RES) connected to tence of a significant number of old substations, which the grid. The Efficient Power is the power output (MW) will require costly interventions to support IEC 60870-5- that a Production Unit may deliver with no deviation for 104, has led to the continued support of IEC 60870-5-101. thermal energy sources, for a set number of hours for a Hydro power plant and in ISO condition for Gas turbines RTUs with a dual configuration which supports both IEC or combined cycle power plants. 60870-5-101 and IEC 60870-5-104 have been installed. In this way, when legacy substations are eventually To comply with the Primary Load-Frequency regulation upgraded to allow the use of IEC 60870-5-104 there will each Production Unit must be confined to a suitable be no need to upgrade the RTUs. power margin between the working set point and the maximum (minimum) power output. That margin is called Figure 8 shows the Italian SAS architecture, highlighting the Primary Regulation Reserve. The sum of all primary the basic systems and equipment involved; the two pro- reserves of the entire grid is the Italian Power System tocol used for communication are also indicated. Primary Reserve. The implementation of the project requires the installa- The Secondary Control restores the power exchange tion of a great number of new components, which can with the interconnected neighboring countries (France, be affected by faults which also applies to previously Switzerland, Austria and Slovenia) at the scheduled set installed equipment. In contrast to previous systems SAS point. The secondary controller, fed by the frequency provides not only the alarms but also the diagnostic infor- deviation ∆f and the power exchange error ∆P , tunes the mation for all the components thus facilitating complete set point of the primary controllers, modifies the output oversight and monitoring of all the equipment. power until the ACE is neglected. The power reserve 28 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 8: ITALIAN SAS ARCHITECTURE Source: Authors Thus, the main achievement of the SAS project devel- This star-wired topology limited the full development of opment is not the reduction of system malfunctions but the SAS project and for the applications that might use this instead a substantial decrease in the time to locate faults system as the topology meant that inter-substation traffic and their causes thus reducing the mean time to repair. was obliged to pass through the control center thus reduc- Consequently, outage times have been reduced lead- ing the speed and flexibility of system operation systems. ing to a significant decrease in the Energy Not Served (ENS) parameter, which is one of the key performance On the other hand, the existing regulatory system could indicators (KPIs) in evaluating the success of any initiative create issues for future developments. One of the deployment in a transmission system. planned upgrades in Terna’s SAS project is the monitor- ing of renewable/distributed generation. To achieve this D.2.6.1 Lessons learnt Terna has to not only make further investments in tele- The Italian SAS experience is a useful illustration not so communication systems but also has to deal with regula- much for its architecture, which is fairly standard, but tory issues regarding data exchange with the distribution rather for the analysis of the constraints imposed on network, where most of renewable/distributed genera- such a project in a mature transmission system charac- tion is connected. terized by consolidated infrastructure and strict regula- tory systems. Some of these constraints are not present or could be avoided in a country like Vietnam, which is in need of a This is especially pertinent to the development of the rapid expansion of the transmission system. In order to GOOSE initiative which was used for intra-substation do this, all aspects of the project will need careful techni- communication, but not for information exchange cal (interconnection between substations) and regulatory between different substations. The existing telecommu- (monitoring of renewable generation) planning. nication system, in fact, already connected all the sub- stations with the control center and to avoid further cost IEC  60870-5-104 was selected as the communication D.2.7 Wide Area Monitoring System protocol between substations that were star-wired from Following the severe blackout that occurred in Italy on the control center. 28th September 2003, the Italian System Operator Volume 1: Technical Analysis 29 (formerly GRTN, now Terna) undertook an action plan about 30 Phasor Measurement Units (PMUs) and a dedi- aimed at improving operational security by enhancing cated data network with monitoring applications for data the monitoring facilities. The Wide Area Measurement processing as well as an intelligent display at the National System (WAMS) project, based on technology which Control Centre in Rome. offers emerging and highly functional solutions for power systems analysis, monitoring and control, commenced in One of the critical aspects of the WAMS project was the 2005 and aimed to provide control room operators with location of the measurement devices or PMUs. As the new, advanced monitoring tools and facilities. number of PMUs necessary to assure complete system observability (e.g. for linear state estimation) would have This was done under the banner of a Terna initiative called been way too numerous, a limited number has been Plan for System Security, with the aim of revising and installed during the first rollout of the system. Device modernizing the network control procedures and analy- locations were selected to maximize the added value of sis tools. the phasor measurements. One major item of this plan was the design and com- The optimal PMU positioning was considered from many missioning of a wide area synchronized network [4], different perspectives. In particular, based on the need as shown in Figure 9, aimed at providing control room to monitor critical portions of the power system, i.e. operators with advanced monitoring tools and automatic areas subject to specific types of events like line trips corrective controls, both phenomenon- and event-based, with possible cascading or voltage collapse, oscillations, linked with a SPS [5]. The basic processing functions that etc., which could jeopardize system stability. The PMU were implemented included automatic alarms, on line positioning strategy was a two-step procedure combin- frequency domain analysis, modal analysis and coher- ing heuristic and analytical criteria. ency areas monitoring. The first step was to apply a number of analytical posi- D.2.7.1 PMU devices and their positioning strategies tioning criteria separately, each one identifying substations The first step of the Terna WAMS project was developed worth equipping with a PMU. In particular, selection crite- over a two year period and involved the installation of ria focused on local and/or system-wide aspects regarding: FIGURE 9: ARCHITECTURE OF THE WAMS APPLICATION AT TERNA (ITALY) Source: Terna-CESI, 2008, (1) 30 Smart Grid to Enhance Power Transmission in Vietnam a. Discrete event identification, such as line/gen- sites. Figure 10 shows the deployment of the first 21 eration tripping, by recording phasors were those PMUs that were installed in the Italian HV grid. events would cause the biggest step-changes of the network key variables (e.g. voltage Critical nodes were equipped with local recording and magnitude); back-up functionality. In case of communication failure, the recording of significant transients is assured and the b. Detection of electromechanical oscillations, by data can be retrieved at a later stage for postevent analy- installing recording phasors close to generating sis. Recording is triggered by events (such as protection units often affected by poorly dumped power intervention) and by specific algorithms for detecting dis- swings; turbances or by external manual activation. c. Voltage stability monitoring, by installing record- ing phasors on busbars significantly affected by The installed PMUs record phasor measurements at a reactive power imbalances (e.g. those with high rate of 50 samples per second (one every 20 ms). The sensitivity); and PMU sampling window is between 20 and 50 ms wide, the processing lag is less than 10 ms. The measure- d. Angle and frequency stability monitoring, by ment errors are within 0.1° for phase and within 0.01% installing recording phasors in areas often subject for frequency. The data provided by the PMUs such as to grid islanding. measurements, time stamps and the other status infor- The operators’ experience was invaluable for formulat- mation is formatted according to a specific IEEE standard ing heuristic based rules to select PMU locations e.g. (originally 1344, then C37 .118) and continuously trans- proximity to large strategic generating units, bottlenecks, mitted to a central server by means of a high-reliability, borders, etc. high-performance redundant communication system comprised of dual data link channels. The second step was to identify the final PMU hosting sites. These locations were selected by combining all The acquired data is stored in a real-time database, the sites selected by the different analytical criteria and hosted in the RAM of the server machine with a redun- those identified by operators’ experience. The final PMU dant real-time back-up server. The monitoring application location list was the best compromise of all the listed programs read the PMU data and write the results to FIGURE 10: DEPLOYMENT OF THE FIRST 21 PMU DEVICES IN ITALIAN HV GRID (LEFT: 400 KV LAYOUT, RIGHT: 220 KV LAYOUT) Source: Cigrè, 2007, (2) Volume 1: Technical Analysis 31 a dedicated area of the database. The database is also line terminals or between generation and load areas is accessed by the alarm management applications. The among the simplest and most effective indicators of sys- memory keeps the data of the last 30 minutes, aligned tem stress. It may also provide a guide for the reconnec- and chronologically sorted by time stamps. Older data is tion activities. moved to a short term circular buffer containing 24 hours sampling at 20 ms, then to a long term archive hosting 30 Moreover, frequency is monitored to detect power imbal- days data sampled at a rate of one sample every 100 ms. ances and to perform an off-line disturbance analysis. Data can be permanently saved on operator request or if Response and effectiveness of the frequency regulation triggered by automatic disturbance detection. and adequacy of the rotating reserve is tested. Figure 11 shows one of the applications developed at TERNA D.2.7.2 WAMS functions and applications National Control Centre in Rome for basic on-line moni- After positioning the PMUs, a second very important toring of the network using WAMS measurements. aspect is the design of the monitoring application func- tions to provide useful information to system operators. Another major application expected from the wide area First, an algorithm for event identification is tested under monitoring synchronized system consists of the modal complete and incomplete observability conditions. In analysis for real time and off-line identification of oscil- parallel the basic monitoring functions for operator sup- latory behaviors. Knowledge of damping is a guide to port concerning voltage, angle and frequency stability are the degree of stability of the operating conditions and implemented. helps identify unstable modes and contributory factors, [6] which directly suggest the countermeasures to be Displays and algorithms are available to closely track the implemented. voltage profile and stability margins and to give early warning of possible voltage collapse. Further, measur- The analyses conducted of the output of the first PMUs in ing the voltage angular difference between important operation on the Italian system confirmed the importance FIGURE 11: APPLICATION THAT COLLECTS SOME BASIC ON-LINE MONITORING FEATURES Source: Authors 32 Smart Grid to Enhance Power Transmission in Vietnam of oscillation monitoring. For this purpose some digital have been implemented in an on-line application, cur- signal processing algorithms have been tested and some rently in operation at the National Control Centre (Rome), off-line and/or on-line applications have been developed. which has made possible real-time monitoring of the net- work. On-line applications have collected a lot of analysis Among these tools one is of particular interest as its results obtained from long registrations (10-15 days) on objective is to extract information from the recorded which it is possible to conduct statistical analysis. signals regarding the power system’s electromechani- cal phenomena [7]. The data processing techniques are Analyzing distribution of frequency and damping is a very devoted to identifying both weakly damped oscillatory useful way of characterizing typical oscillatory modes behaviors (mainly inter-area) and voltage instability (col- crossing the different parts of the electrical network lapses), with particular attention to the time at which (Figure 13 shows an example). In fact, it is very impor- these dynamics took place and their trend. tant to investigate how their damping depends on time of day, load situation, network mesh conditions, amount In this environment a number of algorithms are available, of renewable production and the quantity of power such as power spectral density evaluation, nonparametric exchanged with foreign countries. A particular focus is methods (e.g. wavelet transform), parametric methods brought to bear on renewable production, whose behav- (Kalman filter, Prony and RLS methods), subspace meth- ior is generally less reliable than traditional power plants. ods, maximum likelihood estimation, S-Difference Indica- It has been observed that in situations where there is a tor calculation (assesses voltage stability). An example of high percentage of renewable energy in the total produc- the results available from one of these methods of modal tion, the transmission network in less stable. So, if in analysis is shown in Figure 12, which shows a frequency such conditions a statistical analysis of WAMS data does and damping estimation with model identification per- not reveal any relevant decrease of damping in the typical formed with a Kalman filter. inter-area modes, this may indicate the right environment for the integration of renewable generation. These techniques displayed a considerable potential to identify the frequency and start time of oscillatory behav- The WAMS project is on-going as is the installation of iors in the signals and following a period of off-line testing PMUs and at the time of this report the number of PMUs FIGURE 12: FREQUENCY AND DAMPING ESTIMATION WITH MODEL IDENTIFICATION PERFORMED WITH KALMAN FILTER Source: Terna-CESI, 2014, (3) Volume 1: Technical Analysis 33 FIGURE 13: EXAMPLE OF FREQUENCY AND DAMPING DISTRIBUTION A DOMINANT OSCILLATORY MODE Source: Terna-CESI, 2014, (3) installed on the Italian network has reached in excess of D.2.7.3 Project development and lessons learnt 80 devices. The long term aim is to improve the observ- Whilst the initial purpose of the WAMS project was to ability of network dynamic behavior covering as much of evaluate how effectively it can improve power system the transmission network as possible. security further developments have been driven by the requirements for accelerated response and acceptance Another important step in the development of WAMS times expressed by the operators. One of the major in Italy was its interconnection with the complimentary issues that remain to be analyzed is the integration systems of neighboring countries, for comprehensive between WAMS and SCADA/EMS. In particular improv- control of the interconnected power network and in- ing state estimation, event detection, frequency stability depth monitoring of the power imported by the Italian assessment, islanding detection and restoration tests system. support. 34 Smart Grid to Enhance Power Transmission in Vietnam Furthermore, WAMS data has also been input to an algo- It is appropriate to discuss international experiences of rithm for Dynamic Line Rating. This technique performs such events to ensure best practice regarding implemen- the estimation of the line’s real-time temperature based tation of the most appropriate countermeasures. on the identification of the electrical parameters of the line itself. These parameters may be calculated from the When maximum precision and accuracy are necessary in electrical characteristics (acquired from WAMS) of the locating lightning prone areas, combined with the need line through an adequate electrical model [7]. to cover vast areas, they together provide a compelling argument to install a Lightning Location System (LLS) This WAMS project will be a useful reference in F.5 capable of high efficiency and the ability to precisely cal- because: culate single parameters. One of the best technologies in this field has been applied since 1994 by SIRF® to a. It was developed to deal with issues quite similar develop the Italian LLS. to the ones that occur in Vietnam; The Italian LLS implementation was expressly commis- b. The topic of PMU positioning was investigated in sioned by GRTN (now TERNA) and ENEL (the sole Ital- great detail (involving different TSO functions); and ian power generation company in 1994), to keep track of c. It used a process of progressive integration of lightning events and to acquire data on them in order to new applications as all of them were first tested analyze their correlation with line faults and with protec- off-line, then developed as on-line functions and tion behaviors. finally their outputs were made available as addi- tional features for the system operator (e.g. state The Italian LLS was implemented after a detailed analysis estimation, restoration support, etc.). of the technologies available on the market and of the best sensor positions to cover the entire country with D.2.8 Lightning Location Systems homogeneous and high performance devices. In ‘Annex 2b.v’ the poor performance of exposed 220 kV Figure 14 is an sample of median lightning density lines during lightning strikes is identified as one of the ground mapping for the year 2000 and is typical of the most serious issues affecting the Vietnamese transmis- output available from the Italian LLS system. sion network. Such graphical representations are available thanks to For transmission and distribution networks lightning the data acquired by the sensors installed all over the events are a potential cause of damage, due as much country; Figure 15 shows one of the Italian LLS sensors. to direct strikes on the overhead cables or towers as to indirect hits near power lines, which can induce Since 1994, the Italian LLS has been one of the best per- over-voltages. forming applications in the world, with an uninterrupted, 24/7 detection performance. This system has a proven Further, over-voltages caused by nearby or direct lightning detection efficiency of more than 90% across the whole events may, in turn, result in phase-to-ground and phase- country, a mean location accuracy of less than 500  m to-phase flashovers in power networks. This sequence and an ability to distinguish between cloud-to-ground and of events produces voltage sags at customers’ busses, cloud-to-cloud events with greater than 85% accuracy. which could give rise to serious malfunctions of a large number of devices and is a significant power quality limi- Where electrical performances of power lines are tation factor. involved, the ability to discriminate between cloud-to- ground and cloud-to-cloud are essential together with In electrical systems located in regions with high kerau- very good location accuracy for every single lightning to nic levels, lightning activity is responsible for more than ground event. 80% of the voltage sags that cause apparatus failures. Consequently, the correlation between relay operations All of this information provided by LLS is very useful for a and lightning events is of crucial interest for ensuring Transmission System Operator. Terna in fact considers it power quality improvement, especially in the presence a critical system and relies on real-time lightning informa- of overhead lines. Indeed, appropriate insulation coor- tion to dispatch energy, operate field personnel teams, dination and protection measures can be selected only study protection specifics and identify lightning-prone after the assessment of such a correlation. areas. Volume 1: Technical Analysis 35 FIGURE 14: EXAMPLE OF A LIGHTNING STATISTICS MAP OF ITALY Source: Authors FIGURE 14: LIGHTNING DETECTOR Terna, both at the national control center and in the regional ones, performs realtime monitoring of lightning, 24/7 , across Italy. Control room personnel use the real- time monitoring of lightning daily to verify the impact on power lines, to choose dispatching routes and to guarantee focus on the most urgent repairs. In particu- lar, this application is very useful for system operation because knowing the location of lightning assists control room personnel to correlate network faults with lightning events in real time. Furthermore, TERNA has applied the mean lightning den- sity at ground data provided by the Italian LLS for the evaluation of line faults and assessment of the most exposed branches to be specifically protected with trans- mission surge line arresters. This parameter is always applied in the planning phase of a new transmission line route. Finally, specific studies have been performed on those lines with abnormal fault behavior, correlating lightning and data on faults in order to find out where protection and/or transmission surge line arresters have failed or underperformed. Source: Authors 36 Smart Grid to Enhance Power Transmission in Vietnam D.2.9 Power quality monitoring project Today, the technology is highly effective and can identify problematic conditions. So, a modern PQ monitoring sys- Power Quality (PQ) is a critical issue for transmission tem should contain the analysis tools needed to organize utilities which have among their many roles the duty to and study the collected data. guarantee the quality of supply. Thus, PQ monitoring is an important service that these utilities must perform for Italy approved a plan for the detection of voltage quality both internal and regulatory purposes. on the national transmission network in September 2005 for which Terna developed a PQ monitoring system. The types of disturbances to be monitored are well understood and are mostly due to: In order to acquire data to perform PQ monitoring Terna installed about 200 sensors to cover the most signifi- a. Network failures and faults on customer installa- cant points all over the transmission network; Figure 16 tions (voltage dips and interruptions for the con- shows one of the devices used. sumers connected to the network); b. Rotating machines and transformers inrush cur- All the acquired data is synchronized by GPS and col- rents (rapid voltage changes); and lected in a central elaboration system with the purpose of determining the statistical averages of the main types c. Rapidly changing loads and non-linear loads (Har- of disturbances and understanding both the way in which monics, dips and swells, flicker, etc.). these are propagated across the network and the possi- Furthermore, in the last few years, the spread of Dis- ble correlations with the causes that can generate them. tributed Generation units connected to the transmission network have been known to affect voltage regulation Terna, on the basis of the results of measurement pro- and provide abnormal voltage and frequency variations. grams, has defined the expected levels of voltage qual- Therefore, it is important for transmission utilities to ity, relative to: know the real impact of these new installations in term of PQ delivered to the customers and distribution system a. The maximum annual number of transitional operators. interruptions per-user; b. The maximum value of voltage dips for each user; c. The maximum level of total harmonic distortion; d. The maximum value of the degree of asymmetry FIGURE 16: SENSOR FOR POWER QUALITY MONITORING of three-phase voltage; and (WALLY) e. The maximum value of voltage fluctuation sever- ity indices in the short and long term. By analyzing the data acquired and comparing it with the listed thresholds it is possible to evaluate PQ in the differ- ent parts of the network, to localize problems and to plan actions to address them. In particular, it is possible to identify the probable compo- nents that can cause problems and use that information to direct intervention strategies even when Terna does not own these devices. The Italian TSO in fact has the prerogative to request maintenance and/or replacement of equipment that causes or has been known to cause problems on the transmission grid, especially if they vio- late the PQ standards. Furthermore, Terna considers PQ monitoring system very useful for assessing protection system performance as the data collected can be exploited to identify anomalous Source: Authors protection behaviors. Analysis performed has revealed that in a normal situation most of voltage dips (over 80%) Volume 1: Technical Analysis 37 have a typical duration of 20 and 200 ms (see Figure 17); c. Measurement of electricity injected and/or taken such duration is compatible with the closing speed of the from power units or withdrawal units, at those switches for the intervention of the distance protection points of connection to the network for third measures configured as the 1st step. There is a fair per- parties, and used for commercial purposes (for centage (10%) of holes which lasts up to 500 ms which example in the Electricity Market). correspond, in all probability, to the intervention of the The main task of Metering is to acquire, develop and vali- distance protection measures in the 2nd step. date measures of energy used for commercial purposes by Settlement systems (activities aimed at identifying If the analysis of PQ monitoring data shows an abnormal the amount of energy injected and/or taken from the net- distribution of the events, characterized by an excessive work by each electrical operator) and by billing systems. concentration of voltage dips corresponding to the 2nd So, a Metering System is mainly engaged in the exploita- step of the distance protection measures, this reveals tion of the third type of measurement (i.e. 159.c above). the presence of malfunctioning or incorrect settings in the protection system. The concept of metering as it applies to a transmission network is directly connected to one of the functions of D.2.10 Metering Data Acquisition System a full-service TSO, like Terna, which has to ensure the transmission of electricity from the entry points (power Measurement in the electricity sector is carried out for plants, import from interconnection lines with foreign different purposes, the most important of these are the countries) to the withdrawal points (factories, substa- following: tions, utilities, auxiliary services, etc.). a. Measuring the power in real-time (e.g. every 4 Thus, Terna’s experience of Metering Data Acquisition seconds) for remote monitoring systems; Systems on the transmission network may be very use- b. Measurement of the electricity used for billing ful in particular because the Italian TSO recently upgraded and accounting purposes (to calculate the due its system, under the project name MeTer at the end of amounts); and 2011. It will be helpful to identify the guidelines of the FIGURE 17: CORRELATION BETWEEN THE NUMBER OF VOLTAGE DIPS AND PROTECTION BEHAVIOR Source: Authors 38 Smart Grid to Enhance Power Transmission in Vietnam project and the number of devices involved and to high- connection between these two kinds of Smart Grid proj- light its main challenges. ects (Metering Data Acquisition System and SAS), which are significant for the Vietnamese transmission network Project MeTer’s main business goals and technology were: where both the initiatives are being developed or are in the process of being implemented. a. To increase its level of efficiency and effectiveness; To highlight the two different types of acquisition (direct b. To increase productivity, by improving the level of and indirect) and to show the interconnection between interactivity and of response times; the different systems and devices involved, the sche- c. To improve performance level; matic below shows the structure of Terna’s Metering Data Acquisition System (Figure 18). d. To improve the security policies; and e. To improve scalability, in terms of functional pro- In developing this kind of project Terna had to manage cesses to manage. regulatory issues, especially regarding data-exchange with distributors. Under the terms of the current legis- The total number of installed meters in December 2010 lation, Terna is responsible only for the detection of the was 7,102, allocated as follows: energy transmitted from power plants on national trans- mission networks, while the distribution companies are a. Generation = 2,208 (31.09%); responsible for the detection (as well as the installation of meters) of all energy transit on their networks (entered b. Links to foreign countries = 56 (0.79%); and and withdrawn). c. Withdrawals = 4,838 (68.12%). In order to control the electricity flowing through the Some (4,800) of these meters have been installed in network and in order to be able to acquire the metering indirect mode acquisition using SAS. There is a strong data communicated by distributors, Terna in 2006–2007 FIGURE 18: TERNA METERING DATA ACQUISITION SYSTEM STRUCTURE Source: Authors Volume 1: Technical Analysis 39 signed specific agreements with the various distribution c. Management of any claims received by the elec- companies directly connected to the national transmis- trical operators; and sion network. Such agreements allow Terna to extend d. Power plant inspections. its metering system and acquire metering data directly, however measuring relevant energy entries and energy The generation side is more relevant from the electrical withdrawn from the network is the responsibility of market point of view as measurability is the basic crite- distributors. rion for the admission of a power plant to the electrical market. The measurability of a power plant is verified Although the signing of the agreements has created the when the measurement devices installed are such as to conditions for a regulated discussion on measuring the allow, using appropriate algorithms, the measurement energy withdrawn, which was, prior to this agreement, of the net electrical energy traded by the power plant impossible to achieve, some difficulties remain. There are from the point of entry to the power grid to which it is some issues regarding the location and registry of the connected. plants and the lack of leverage with distributors. In order to address this aspect, in April 2011, Terna asked the electrical authority to intervene by authorizing Terna D.3 Europe to apply commercial market rates for energy flows tran- siting its network and to reduce the number of repeated Paragraph ‘D.1’ presented the European as an example and late adjustments of withdrawals from the network. of best practice for the following reasons: Moreover, in implementing the MeTer project, Terna dealt a. The European Commission’s ENTSO –E Ten-Year with two key technical points: Network Development Plan 2014 [3] as best practice in the future development of intercon- a. The correct identification of that portion of the net- nections between Vietnam and its neighboring work (with the obligation to connect third parties) countries. Moreover, this plan highlights the to which the power plant is connected as it is very importance of shared N-1 criterion assessment in important to identify responsibility for the collec- a large interconnected system. tion, validation and recording of electrical data. b. The Reactive Power Compensation in the UK, b. The correct identification of the voltage level on adopted by NGC, to ensure the control and regu- that part of the network to which the power plant lation of reactive power exchange and therefore is connected as this is fundamental both from a the proper management of the voltage profiles in commercial point of view and for balancing the a transmission system. power levels of the network. D.3.1 ENTSO–E European Ten-Year Network An analysis of Terna’s experience highlights the main Development Plan activities of a metering process from the technical point D.3.1.1 Background of view as given below. The original purpose of the European interconnected transmission infrastructure was to provide an essential a. Acquisition of the measurements from the field backbone to ensure the security of supply in continental through a direct acquisition model; Europe. The system has been evolving over the last 50 b. Recovery/reconstruction of missing data and cor- years with a view to assuring mutual assistance between recting transmission errors; and national subsystems. However, there has been a funda- mental paradigm shift over the past decade or two. The c. Processing and aggregation of measurements. European transmission infrastructure is no longer just a tool for mutual assistance but has become the platform Furthermore, the generation side demands: for shifting ever increasing power volumes across the continent. a. Qualitative analysis of the measurements through comparison with the data acquired by Terna’s sys- Market development has resulted in higher cross-border tem (Remote Control, Programs, Limits); exchanges with short-term commercial objectives. Other b. Validation and publication of aggregated input cross-continental power flows result from the rapid and and withdrawals from single power plants; successful deployment of regional intermittent energy 40 Smart Grid to Enhance Power Transmission in Vietnam generation with low predictability (e.g.: wind power). small power flow deviation could start line trips cascad- These developments were not taken into account in the ing across the Europe-wide network. original system design. Between 22:00 and 22:10 (4 Nov, 2006) [8], as the power Furthermore, due to environmental reasons, the develop- flow on the Landesbergen-Wehrendorf line increased, it ment of the transmission system is increasingly affected triggered a line trip that cascaded across a number of by stricter constraints and limitations in terms of licens- other networks thus proving the point about the impor- ing procedures and construction times. Many UCTE tance of the N-1 criterion. The tripping of several high- TSOs are facing significant difficulties with building new voltage lines split the UCTE grid into three separate areas overhead lines due to long authorization procedures and (West, North-East and South-East as shown in Figure 19 regulatory regimes. below) with significant power imbalances in each area. In the Western area this power imbalance induced a severe D.3.1.2 2006 European areas separation frequency drop that caused an interruption of electricity This situation led TSOs to operate the system closer and supply to more than 15 million European households. closer to its limits as defined by current security criteria based on the physics of the system. This, therefore, will As a response to this crisis the automated countermea- remain of decisive relevance for the secure operation of sures in each individual TSO responded quickly avoiding the electricity transmission infrastructure. further deterioration of the systemic conditions. Within 38 minutes of the network splitting as a result of the On November 4, 2006, there were significant East-West cascade tripping, the TSOs were able to recover the full power flows as a result of international power trades and resynchronization of the UCTE system and then to re- the obligatory exchange of wind power feed-in within establish a steady-state situation in all European coun- Germany. In this situation the 380 kV double circuit line tries in less than 2 hours. Conneforde-Diele in Germany was switched-off and the E.ON Netz grid was not in a “N-1” secure configuration. D.3.1.3 Situation awareness and remedial actions This incident focused UCTE’s attention on two main Following this disconnection the resulting power flows issues: on other lines in the 380 kV Landesbergen (E.ON-Netz)- Wehrendorf (RWE TSO) network were so close to the a. N-1 criterion assessment; and thresholds of the protection system that even a relatively b. Inter-TSO coordination. FIGURE 19: FREQUENCY TRENDS AND AREA SEPARATION Source: UCTE, 2006, (4) Volume 1: Technical Analysis 41 The N-1 criterion is a basic operating principle within interregional TSOs is necessary. So, UCTE Recommen- UCTE and is critical to prevent disruptions from spread- dation 4 [3] was drafted with the purpose of setting up ing. This rule requires that any single loss of transmission an information platform allowing TSOs to observe in real- or generation element should not jeopardize the secure time the actual state of the whole UCTE system, in order operation of the interconnected network, that is, trig- to react in a prompt and timely manner during significant ger a cascade of lines tripping or the loss of a significant power disruptions. amount of consumption. Recommendation 1 [3] requires the TSOs to review the application of the N-1 criterion in The European Ten-Year Network Development Plan has terms of: been developed over an extended period and Europe’s new electricity paradigm is driven by three main factors: a. Defining the relevant parts and specific condi- tions in the adjacent systems which have to be a. EU energy policy deriving from the EU’s “20- taken into account in the TSOs security analyses; 20-20” objectives and the recently adopted EU Energy Roadmap 2050; b. Simulating the contingencies (tripping of power system elements) located outside the TSOs own b. The IEM, which is to be completed by the target control area; date of 2014 as defined by the EU Council in Feb- ruary 2012; and c. Mandatory and regular online contingency analy- sis (N-1 simulations) connected to the alarm pro- c. The deployment and implementation of the cessing system; and Smart Grid. d. Preparation and regular checking of the effi- These principles will make the European energy market ciency of remedial actions through computer completely reliant upon its strong transmission backbone simulations. while continuing to maintain security of supply and lib- erating the electricity market. The Smart Grid roadmap, The prompt and successful application of the proper whose impacts and benefits are emphasized in Figure countermeasures within a few minutes of an incident 20, will allow the European manufacturers and ICT pro- demonstrates the efficiency of the decentralized respon- viders to develop innovations and bring them to market. sibilities of TSOs. In any case Inter-TSO coordination is Furthermore, the cooperation with research partners will crucial for maintaining the security of the system. This create new opportunities and allow ENTSOE to further co-ordination has to be exercised over different time refine this roadmap in the coming years creating syner- scales, from long term planning to real time opera- gies that can be exploited in Europe to reduce costs and tion. In order to achieve this aim the development of maximize results. standard criteria for coordination between regional and FIGURE 20: IMPACTS AND BENEFITS OF SMART GRID ROADMAP Source: Authors 42 Smart Grid to Enhance Power Transmission in Vietnam D.3.1.4 Identifying Bottlenecks and Transmission c. Market integration: If inter-area balancing is at investment needs stake a distinction needs to be made between The strategy for the definition of the needs of the trans- that which is internal to a price zone and that mission network deserves particular focus. A market and which is between price zones (cross-border). network study has been performed and, as a result, about The analysis of the bottlenecks highlights that the most 100 bottlenecks have been identified (shown in Figure 21). critical area of concern is the stronger market integration within mainland Europe of the four main “electric penin- The bottlenecks occur in those grid sections where the sulas” in Europe, highlighted in Figure 22. transfer capabilities may not be large enough to accom- modate the likely power flows that will need to cross These are all large systems (50-70 GW peak load) sup- them and in the coming decade new transmission assets plying densely populated areas with high RES develop- will be required in order to ameliorate these bottlenecks. ment prospects, and as such, they require much greater The likely bottlenecks have been listed according to three interconnection capacity to enable the development types of concern: of wind and solar generation. To this end, intercon- nection capacities should double on average by 2030. a. Security of supply: When some specific areas Investment needs are likely to trigger extra-high volt- may not be supplied according to expected qual- age grid investments in order to restore the grid’s abil- ity standards and no other issue is at stake; ity to fulfill the duties and services expected from the b. Direct connection of generation: Both thermal infrastructure. and renewable facilities; and FIGURE 21: MAP OF MAIN BOTTLENECKS IN THE ENTSO-E PERIMETER Source: ENTSO-E, 2014, (5) Volume 1: Technical Analysis 43 FIGURE 22: THE FOUR MAIN “ELECTRIC PENINSULAS” IN EUROPE Source: ENTSO-E, 2014, (5) D.3.1.5 ENTSO-E Committees targets f. To strengthen collaborations between TSOs and Finally, the ENTSO-E committees have utilized both bot- DSOs in their efforts to integrate distributed tom-up and top-down design approaches to define six energy resources. roadmap targets for 2050 as follows: D.3.2 Reactive power Compensation in UK – a. To facilitate development of a pan-European grid NGC experience architecture that fulfills the lowcarbon require- ments of the Energy roadmap for 2050 and D.3.2.1 Reactive power compensation data enables effective power delivery throughout With reference to the analysis in ‘Annex 2b.iii’ and with Europe; particular reference to the use of SVC systems in the following sections, some notes and information are dis- b. To demonstrate, understand and appraise the cussed relating to the implementation and use of these impact and potential benefits of state-of-the-art FACTS devices in a significant transmission network as power technologies and offshore solutions; that of NGC, UK [9]. c. To design and validate novel ICT-based method- ologies for network operation that meet the reli- The configuration of the transmission network system is ability targets of both today and tomorrow; shown in Figure 23. d. To develop the market designs for the IEM that The schematic below Figure 24 shows the rating and is most beneficial for system operators, market localization of reactive power compensation systems participants and consumers; based on the configuration of the 400/275 and main 132 e. To determine and develop an optimal asset man- kV systems in UK. agement strategy for equipment on a cost-effec- tiveness basis; and 44 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 23: UK NGC TRANSMISSION MAP Source: National Grid – UK, 2014, (6) Volume 1: Technical Analysis 45 FIGURE 24: UK REACTIVE COMPENSATION MAP Source: National Grid – UK, 2014, (6) 46 Smart Grid to Enhance Power Transmission in Vietnam Reactive power compensation and system voltage con- trol is obtained with a combination of: FIGURE 25: UK SVC LOCATION MAP a. Reactors, both connected directly to HV or to Ter- tiary windings of transformers (60 Mvar/33 kV, 60 Mvar/132 kV, 100 Mvar/275 kV, 150 Mvar/400 kV); b. Mechanically Switched Capacitors (45-60 Mvar/132 kV, 150 Mvar/275 kV, 225 Mvar/400 kV); and c. SVCs (typically 150 Mvar connected through a dedicated transformer to 275 or 400 kV, and 60 Mvar, connected to tertiary winding of substation transformer). There are 40 installed SVCs with a total installed capacity of more than 4,000 Mvar, roughly a third of the Reactive power provided by the remaining mechanically Switched Capacitors, to be compared with a total installed capacity of around 93 GW, to serve a peak demand of around 60 GW. A systematic installation of reactive compensation sys- Source: Cigrè, 2000, (7) tems in the event of substantial expansion phases of the network or in case of significant increase in the load profiles and thus the need to provide rapid support of the served in a certain area of the grid adopted by NGC related regulation. allows for the efficient use of the network assets, sat- isfying locally, as far as possible, any request for a reac- Figure 25 identifies the location of the SVCs within the UK. tive power demand that is not covered for example at the level of the distribution network. Then, the option to D.3.2.2 New SVCs installation install a FACTS device instead of a traditional mechani- The table in Figure 26 shows the anticipated incremen- cally Switched Capacitors is normally considered and tal changes and implementations, scheduled over the activated in the nodes where the network analysis shows next decade and concerns the reactive power equipment the presence of major problems in the control of voltage within the SVC installation. FIGURE 26: UK SVC DEVELOPMENT PLAN 2014-2024 Source: ENTSO-National Grid - UK, 2014, (6) Volume 1: Technical Analysis 47 The installation or relocation of a further 10 SVCs is “Network reinforcement is not just about new capacity planned within this scenario, where a combination of dif- but can also mean releasing the latent capability of the ferent systems is also anticipated. system. This is achieved by enabling technologies, which do not deliver capacity alone, but as part of a network will D.3.2.3 NGC strategy for reactive power compensation improve transfer capacity or improve stability, which will NGC plans the use of FACTS devices to address specific allow higher boundary transfers. Where network param- issues related to the operation of the network, as shown eters such as voltage, fault tolerance or stability are the in the table labeled Figure 27. limiting factors then reactive compensation can be used to improve regulation and thereby regional power capac- The strategy that is the basis of the application of FACTS ity. Static VAR compensators (SVCs) and STATCOMs are devices can be summarized in the following two NGC used to retain voltage stability during fault conditions. In statements. marginal cases, this can avoid the need for new circuits for security of supply”. “Reactive power compensation devices provide volt- age support when voltage needs to be increased or The illustration in Figure 28 shows the contribution pro- decreased. This might be during the minimum demand vided by two of the installed SVCs, namely the SVCs at periods when voltage is often too high or after a fault Harker substation, 2 x 150/-75 Mvar, that provide signifi- when there is rapid and significant voltage depression cant support to the transient and dynamic stability mar- that needs reactive power injection to recover the volt- gins, increasing the power transfer limits from Scotland age level as quickly as possible. This response can be to England, thus addressing the unbalanced distribution provided by a range of devices, such as capacitors, reac- of generation in the north and the primary load present in tors, Static VAr Compensators (SVCs), static synchronous the southern part of the grid [10]. compensators (STATCOMs), or generation assets. These devices have various capabilities and the best solution D.3.2.4 Re-locatable SVCs is chosen based on the type of voltage management Some comments can be made with reference to the spe- required and the local system parameters” . cific development of standardized re-locatable solutions. FIGURE 27: NGC SELECTED TRANSMISSION SOLUTIONS Source: National Grid - UK, 2014, (6) 48 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 28: EXAMPLE OF TRANSIENT STABILITY ENHANCEMENT Source: Cigrè, 2000, (7) The development of these solutions was started in the of around 60 Mvar and directly connectable to the ter- 90’s in order to address the need for an additional degree tiary winding of the existing substation transformer [11]. of flexibility in the planning of the network required The typical connection schema is shown in Figure 29, mainly because of the introduction of the unbundling of whereas the typical lay-out, based on modular skids, the assets of the electrical system. transportable by truck, is shown in Figure 30. The first family of re-locatable SVCs introduced in the grid The following steps have led to the increase of SVC rated was based on TSC modular systems with a rated power power to values of 150 up to 225 Mvar with the possibil- ity of connection via dedicated transformer to the 400 or FIGURE 29: RE-LOCATABLE SVC CONNECTION SCHEME 275 kV network. In this case the basic requirements set by NGC were rel- evant to: a. A wider operating range with higher reactive power output; b. The availability of faster dynamic response characteristics; c. A modular converter design to allow for a wide range of selectable ratings; d. Re-locatable cabin-based design to assure maxi- mum operational flexibility with the ability to relo- cate within 6 months; and e. Availability > 98%. The resulting system schema, shown in the following Figure 31 saw the introduction of a STATCOM device (equipped with GTO or IGBT’s), which ensures greater system functionality [12]. The corresponding lay-out Source: CigrèABB, 2013, (8) remains very compact, as shown in Figure 32. Volume 1: Technical Analysis 49 FIGURE 30: RE-LOCATABLE SVC TYPICAL LAYOUT Source: ABB, 2013, (8) FIGURE 31: RE-LOCATABLE SVC EQUIPPED WITH VOLTAGE FIGURE 32: RE-LOCATABLE SVC EQUIPPED WITH VOLTAGE SOURCE CONVERTER SOURCE CONVERTER. TYPICAL LAYOUT Source: ALSTOM, 2013, (9) Source: ALSTOM, 2013, (9) D.3.2.5 Optimal strategy for reactive power compensation, Reactive power compensation devices have various lessons learnt capabilities and the best solution should be chosen The following main points emerge from the analysis of on the basis of the specific type of voltage manage- the experience of the UK, regarding the optimization of ment required within the context of the local system the reactive power management. parameters: 50 Smart Grid to Enhance Power Transmission in Vietnam a. For “strong” nodes and areas where there are no A solution that could limit this risk and in turn optimize problems with voltage regulation or there is the the use of FACTS devices is the application of re-locat- availability of local generating units that may par- able or semi-portable systems. In this way, these sys- ticipate in the voltage regulation, the installation tems can be quickly installed/or moved to network nodes of the traditional mechanically Switched Capaci- that reveal operational problems, resolving the issues tor is more than enough to ensure the correct in the short term, while allowing the implementation of reactive power compensation, with the least eco- other more strategic structural network reinforcements nomic impact but with good management of the that require longer completion times. transmission grid asset. b. It is possible to identify some nodes or network areas where the ability to rapidly adjust the con- D.4 USA tribution in the exchange of reactive power is important to ensure the stability of the network The USA’s electrical network is comprised of a large num- and therefore the installation of FACTS devices ber of transmission systems and in most cases the TSO becomes the most suitable option. organizational structure is comprised of an ISO that con- trols a number of WOs. Whilst such a network structure c. In contexts where the configuration of the net- is quite unlike both the Italian and Vietnamese models, work changes very rapidly and substantially, it could still serve as a best practice benchmark for the in particular in the case of connections of large development of some strategic or tactical projects within renewable energy sources, this kind of solution the Vietnamese system. becomes offers the most flexible approach. d. This is especially true in all cases where there The experiences in the USA offer examples of best prac- is the need to compensate for rapid fluctuation tice as follows: of load or generation, which impacts the level of power quality. a. PMU installations and the subsequent develop- ment of the WAMS application; When a network reinforcement is required it is tradition- b. Two different projects regarding Dynamic Line ally achieved by installing new standard equipment, i.e. Rating; lines and new substation bays, but a different approach can be considered in some cases, that is both more prac- c. The BC Hydro case is a good reference to evalu- tical, convenient and which unleashes the latent capabil- ate the opportunity to install sensors for on-line ity of the existing system. DGA on new and old power transformers; and d. A new type of application developed with HVDC This is achieved by applying enabling technologies, which systems. do not deliver capacity alone, but as part of the network, improve transfer capacity or stability and which allow higher boundary transfers. D.4.1 Phase Measurement Units—NASPI roadmap Where network parameters such as voltage, fault tol- Following a blackout in 2003 in North Eastern United erance or stability are the limiting factors then reactive States and Eastern Canada the NASPI (North American compensation and in particular FACTS devices (e.g. SVC) Synchrophasor Initiative) roadmap was developed based can be used to improve regulation and thus regional on NERC (North American Electric Reliability Corpora- power capacity. tion) priorities and goals (shown in Figure 33). One factor that has often limited the use of FACTS NERC is the electricity reliability organization for North devices apart from their high cost is the risk that a rapid America and its jurisdiction includes users, owners, and development and expansion of the transmission grid operators of the bulk power system that serves more could make these devices redundant at the installation than 334 million people [13]. It is a not-for-profit interna- node after a few short years following their commis- tional regulatory authority whose mission is to ensure the sioning, thus making the investment both uneconomical reliability of the bulk power system in North America. Its and unattractive when compared with more traditional responsibility spans the continental United States, Can- alternatives. ada, and the northern portion of Baja California, Mexico. Volume 1: Technical Analysis 51 timescales and costs of each FIGURE 33: NERC PRIORITIES AND GOALS proposed application. They ini- tially defined a list of applications to be created and identified the components to be installed. For all of these applications they set: a. Priority: Needs and Criticality; b. Deployment challenges; and c. Time to complete. In this way NASPI was able to design a “Phased roadmap”, as shown in Figure 34. A further and more complete roadmap was developed in 2012 that introduced 26 applications Source: NASPI, 2011, (10) to be implemented over 5 years (as shown in Figure 35). Starting with these priorities and goals NASPI developed It is a useful exercise to analyse this roadmap as much its Synchrophasor roadmap. The first one was defined for its approach as for the high number of applications in 2006 and took account of priorities, challenges, identified. The most interesting feature is that NASPI FIGURE 34: 2006 NASPI ROADMAP Source: Cigrè, 2013, (11) 52 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 35: 2012 NASPI ROADMAP Source: NASPI, 2014, (12) prioritized the applications that were most significant in Monitoring” which then evolved into “Angle/Frequency/ the context of NERC’s priorities and goals. Voltage/Flow Monitoring, Trending and Alarming” , or added some dedicated applications for a specific need They then prioritized the applications on a timeline and (like “Mode Meter and Mode Shape identification”) that thus created a phased roadmap. This is very important was previously merely an ancillary function of another because it takes account of all the different aspects of application but which evolved into a discreet requirement implementation (necessity, deployment challenge, time in the second iteration of the roadmap. Moreover, the to complete) and allows effort to be focused on those growth of the network during the lifetime of the roadmap challenges that need attention first. implementation gave rise to new requirements, such as “Wind Site Voltage Control” , that had not even been con- Furthermore, this approach also created a complete plan sidered in the first iteration. that predicted when particular applications would be available and reduced the degree of uncertainty in their Further, this iterative revision process allows needs and development. criticalities to be constantly reviewed and re-evaluated. For example, “ Adaptive Protection” application, which in the first The NASPI project approach also demonstrates that it is roadmap was deemed a medium priority with a medium useful to revise and modify the roadmap during the life- development difficulty, had, in the revised roadmap, become time of its implementation in order to add further appli- a critical need and reassigned as a high development chal- cations that arise from the experience of the on-going lenge. On the other hand the “Congestion Management” activities to date and which address the emerging needs application that in the first revision of the roadmap was of the evolving network structure and behavior. both critical and difficult to implement had become less important and easier to deploy in the 2012 iteration. For example, the experience acquired during the Smart Grid implementation process added more detail to Finally, this revision process is also a useful way of mea- already developed applications like “Angle/Frequency suring and monitoring the performance and relevance of Volume 1: Technical Analysis 53 the roadmap in the dynamic context of present day needs and exigen- FIGURE 36: NASPI ROADMAP: “INVESTMENTS 2010-2013” cies. An example is how the “Volt- age Stability” application became increasingly less critical over the two iterations of the roadmap prob- ably as a function of the experiences acquired with the subject during the lifetime of the iterations of the roadmap. D.4.1.1 Investments and accomplishments The SGIG (i.e. Smart Grid Invest- ment Grant) synchrophasor projects were included as part of the NASPI project set [14], [15]. Thanks to SGIG there are ten more synchrophasor projects underway involving 57 utili- Source: NASPI, 2011, (10) ties and grid operators across the U.S. These projects have installed about 850 networked PMUs which, by 2013 were operat- Reinvestment Act of 2009 provided the DOE with $4.5 bil- ing in nearly all regions of the country. lion to fund projects that modernized the Nation’s energy infrastructure and enhanced energy independence. The total budget of the SGIG projects is more than $300 million and includes 50% from Recovery Act funding which The next two figures (Figure 36 and Figure 37) show the made the projects collectively the single largest synchro- project investments of different utilities and the applica- phasor effort ever undertaken. The American Recovery and tions implemented. FIGURE 37: NASPI ROADMAP: “APPLICATIONS ON PMUS” Source: U.S. Department of Energy, 2014, (13) 54 Smart Grid to Enhance Power Transmission in Vietnam Main application achievements are in the following areas: been working with the National Institute of Standards and Technology Smart Grid interoperability standards in an a. Real time observation of system performance; effort to accelerate development of new technical stan- dards for synchrophasor data, equipment and systems. b. Early detection of system problems; c. Real time determination of transmission capacities; D.4.2 Devices for Dynamic Line Rating— d. Analysis of system behavior, especially major NYPA and Oncor DTCR projects disturbances; Among all the possible Smart Grid applications Dynamic e. Special tests and measurements; and Thermal Circuit Rating (DTCR), also known as Dynamic f. Refining of planning, operation, and control pro- Line Rating (DLR), is one of the most significant thanks cesses essential for best practice in the use of to its ability to enable transmission system operators/ transmission assets. owners to mitigate or avoid the costs associated with transmission system congestion. It is worth noting that there are a significant number of possible applications that can use WAMS data, which The U.S. experience with this subject is very instructive. is why PMU installation greatly increases the potential The New York Power Authority (NYPA) and Oncor Elec- for effective monitoring and control of the network. The tric Delivery Company (Oncor), through the U.S. Depart- result of the deployment of such applications, in fact, ment of Energy’s Smart Grid Demonstration Program aims to reduce grid congestion, permit more electricity (SGDP), implemented two demonstration projects [16]. to flow through existing wires and provide early warning They installed dynamic line rating (DLR) technologies to of disturbances to enable timely preventative or remedial increase the efficient use of the existing transmission actions. network, mitigate transmission congestion and develop best practices for applying DLR systems. D.4.1.2 Lessons learnt The table in Figure 37 shows that of all the ISOs that It is very interesting to analyze both projects because joined NASPI, the WEEC (Western Electricity Coordi- they were developed by two very different companies, nating Council) succeeding in implementing the larg- the first being America’s largest state power organiza- est number of planned applications. But the real added tion, with 16  generating facilities and more than 1,400 value of the NASPI experience is the strategy behind the circuit-miles of transmission lines while the second, planning of a very large organization involving a group of Oncor, is the largest regulated electric delivery business ISOs that installed PMUs and developed applications for in Texas supplying electricity to approximately 7 .5 million their individual WAMS projects whilst adhering to shared consumers. objectives. DLR technologies enable transmission owners to deter- Furthermore, the experiences acquired during the imple- mine capacity and apply line ratings in real time. This mentation process were shared in order to revise the enables system operators to take advantage of addi- roadmap in terms of priorities, deployment challenges tional capacity when it is available. Both demonstration and time to complete of the application planned. This is a projects confirmed the presence of real-time capacity good reference point even for smaller organizations such above the static rating, in most instances, with up to as a single TSO where all the different functions contrib- 25% additional usable capacity made available for sys- ute their experiences and emerging understanding to the tem operations. periodic review of the roadmap with a particular focus on how the experiences gained during its implementation NYPA worked with the Electric Power Research Institute have changed their perceptions of application priorities, (EPRI) using technologies and approaches that EPRI had deployment challenges and timescales. developed, while Oncor deployed Nexans’ commercially available conductor tension-monitoring CAT-1 System; Finally, the NASPI experience highlighted the importance Figure 38 provides a brief overview of the two projects. of interoperability, which is paramount for synchropha- sor technologies to succeed, as data must flow across NYPA’s project involved a wider set of DLR technologies multiple transmission system owners’ synchrophasor whilst Oncor’s was larger in scale and aimed for a higher systems, transmission systems, and communications degree of integration with utilities and Independent Sys- networks. Towards this end many NASPI members have tem Operators (ISO). Figure 39 sums up the main objec- tives and outcomes of the two projects. Volume 1: Technical Analysis 55 FIGURE 38: PROJECTS DESCRIPTIONS Source: U.S. Department of Energy, 2014, (14) 56 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 39: PROJECTS OBJECTIVES AND OUTCOMES Source: U.S. Department of Energy, 2014, (14) D.4.2.1 NYPA project The project was launched in 2010 and concluded at the NYPA was interested in studying DLR technologies end of January 2013. One of the most important NYPA because the utility transfers significant amounts of discoveries is that whilst DLR technologies are reliable, power (particularly power generated by hydroelectric the learning curve to implement them is significant. So it plants in northern New York and wind farms in western is crucial to perform a detailed analysis to determine if a and northern New York) across great distances to the particular line is a good candidate for increased real-time south-eastern New York population centers within a his- capacity before procuring and installing the technology torically constrained transmission system. which then have to be properly operated and maintained. Volume 1: Technical Analysis 57 NYPA’s project involves many types of DLR devices, so D.4.2.2 Oncor’s project their performance and reliability had been exhaustively Oncor’s project, on the other hand, required about ten- investigated. Most of NYPA’s reliability concerns were times the investment of NYPA’s project and was primarily with its own communications devices but all of the based on Nexans’ CAT-1 System. The CAT-1 Transmis- DLR devices also experienced reliability issues. In most sion Line Monitoring System allows accurate real-time cases, these issues were related to the significant learn- rating of transmission lines by monitoring the mechani- ing curve for deploying a DLR system, rather than to the cal tension of both ruling span sections of a dead-end design or quality of the devices. structure. Thus, sags, clearances and average conductor temperature are all directly related to CAT-1 measure- The use of new devices led NYPA to perform an assess- ments while the actual line rating is calculated using this ment of the DLR equipment installation process. NYPA’s information together with data from the EMS/SCADA line crews did not have experience of the specialized system. instruments required for DLR systems so they received comprehensive training from EPRI. The installation pro- The aim of the project was to remove the constraints cess itself was improved and streamlined and overall that prevent utilities from using DLR technologies and NYPA determined that a well-trained line crew could to demonstrate the effective use of dynamic ratings to install certain types of DLR devices without causing any reduce grid congestion. In particular Oncor was inter- outages or drop-outs. Furthermore the training process ested in implementing a DLR system because many of for and knowledge transfer of DLR technologies was cru- its transmission paths, including those selected for this cial for the NYPA control center. project, were suffering from significant transmission capacity constraints. The main aim of NYPA is to use dynamic ratings to deter- mine a correlation between increased wind generation Oncor discovered that the average increased real-time and increased transmission capacity. The knowledge of capacity delivered by dynamic ratings was 6%-14% this relationship could inform transmission planning stud- greater than the ambient-adjusted rating for 345 kV lines ies and encourage higher expenditures on transmission and 8%-12% greater than the ambient-adjusted rating for projects. Figure 40 below shows how the thermal con- 138 kV lines. stant of the lines depends basically on wind and, con- sequently, the maximum capacity gain of the lines is The availability of the added capacity ranged from 83.5% achievable in the presence of high wind. of the time under all operating conditions to 90.5% of the time when outages and anomalies were excluded from NYPA has demonstrated that a small project with very the calculations. Those increased capacities can be safely specific and clear objectives can enable the comprehen- delivered within a market structure while ensuring lines sive testing of a number of DLR devices, which could will always be operating within their safety limits. eventually be used in future projects on a larger scale. This has proved useful for planning strategies. Once Oncor did not want to evaluate DLR technologies, rather again this is a good example of cooperative interaction it sought full-scale and real-time integration with its own between different functions of a TSO: i.e. operation, operations and ERCOT’s (a Texas ISO) wholesale electric- asset management, grid construction and planning. ity market. So the most significant outcome of Oncor’s project was the integration of a DLR system with ERCOT‘s control FIGURE 40: FACTORS INFLUENCING THE DYNAMIC RATING room. This direct feed to transmis- sion owners’ communication and control systems, in fact, eliminated the need for the operator to manu- ally view, interpret, and apply the dynamic rating. D.4.2.3  Lessons learnt To conclude, the key outcomes of the two SGDP projects were NYPA’s assessment of the benefits and dis- advantages of DLR technologies Source: U.S. Department of Energy, 2014, (14) and Oncor’s demonstration that 58 Smart Grid to Enhance Power Transmission in Vietnam dynamic ratings can be automatically applied in different approaches to increasing ratings through line real-time system operations. rebuilds, reconductorings, and DLR installations. The two projects revealed opportunities to enhance It is worth noting that the installation of DLR systems future DLR deployments by ensuring the reliability of is often only a fraction of the cost of other solutions DLR data, pre-emptively addressing cyber security con- although the increase in capacity is less than with other cerns, integrating dynamic ratings into system opera- transmission upgrades. tions and verifying the financial benefits of DLR systems. The verification of the actual financial benefit of DLR sys- D.4.3 Sensors for on-line Dissolved Gas-in-oil tems to the transmission grid and to system operators Analysis—BC Hydro case is probably the biggest challenge. The capacity gained by Power transformers are critical to the electric power sys- dynamic ratings can be quantified, and the availability and tem and the utilities are focused on reliability-centered reliability of the technology and instrumentation can be maintenance of their assets for extended lifespans and measured. However, the economic benefit in real time maximum return on investment. The deterioration of a is difficult to quantify, especially as it relates to conges- transformer’s internal components results in the produc- tion mitigation. This is because system operators are not tion of combustible gases that dissolve in the transform- currently able to perform real-time “what-if” scenarios of er’s oil. Because of this, utilities have long incorporated economic benefits with or without dynamic ratings. transformer oil testing into their asset management programs. Furthermore, the congestion of transmission lines is so volatile and transient that it is difficult to compare current Asset managers have learned from experience that and historical grid operations and congestion costs. Pre- checking for fault gases just occasionally is not always dicting future grid capabilities is even more challenging. sufficient to detect problematic conditions that may develop quite rapidly (i.e. in days or hours). In response to Another challenge is verifying the financial benefits of this issue, utilities have begun installing monitoring sys- DLR technologies to the transmission owner. A good tems that perform remote dissolved gas analysis (DGA) approach is to calculate the cost savings that DLR sys- on a near-real-time basis and transmit results to central tems unlock thus precluding the immediate need for monitoring stations. more extensive capital investments. Figure 41 compares FIGURE 41: ALTERNATIVE SOLUTIONS COMPARING Source: U.S. Department of Energy, 2014, (14) Volume 1: Technical Analysis 59 Many utilities have chosen to equip only the transformers The results obtained in this station have proven to BC generally considered to have age related problems with Hydro that on-line DGA is a financially sound invest- remote monitors. The investment cost at US$55,000 per ment. On-line DGA sensors have been shown to be an unit is in fact quite significant. On the other hand, there effective early-warning system that can indicate when are justifications for the wide use of monitoring systems maintenance is required and confirm if the maintenance of which the main one is the necessity to validate the performed was effective. effectiveness of maintenance programs on transformers of any age. BC Hydro’s experience also shows that monitoring systems can help to extend the life of transformers by Viewed in comparison to the cost of replacing a trans- enabling them to be run at decreased load until they are former, remote monitoring devices are a fraction of the replaced or until a permanent repair is made. Prior to the cost of replacing the transformer, which is in the order of ability to do continuous monitoring the protocol was to $2-$3 million and entails about two-year lead time. rely on laboratory analysis of transformer oil which meant taking the suspect transformer out of service to await Therefore some utilities are considering the value of on- the test results. line DGA as part of their maintenance programs. At BC Hydro, an incident with a transformer that was nowhere BC Hydro is considering a plan to specify that every new near the end of its life cycle showed the value of monitor- transformer it buys be installed with an on-line monitor. ing such units in general. The utility is also considering an engineering standard to determine when old transformers with gassing concerns Four generator transformers are installed at BC Hydro’s need to have on-line monitoring installed to ensure the Seven Mile Generating Station. The 225-MVA T1, T2 and safe and reliable operation of the transformer. Mainte- T3 transformers were installed in 1978, and the 233-MVA nance managers feel this makes sense when contrasting T4 transformer was installed in 2003. All four transform- the modest cost of the monitor with the exponentially ers were equipped with gas detector relays. higher cost of the transformer. In 2004 T1 had a gas relay alarm caused by an internal short circuit between the core and the frame due to failed D.4.4 HVDC application—PG&E Example or contaminated insulation. In 2011, T2 had a gas relay Historically, there are many examples of traditional alarm caused by an internal high-voltage bushing failure. HVDC systems, installed in the USA or cross-border to Canada, both to ensure the interconnection of asynchro- These two events motivated BC Hydro management to nous networks, and to allow bulk power transmission across examine the other transformers at the station. The utility significant distances. However, in the last few years, various decided to install eight-gas fault monitors on each of the transmission network operators in the USA have also had transformers at the generating station since these two fail- to face some problems similar to those experienced by the ures had not been detected by traditional oil testing methods. Vietnamese grid, where the primary requirement was an increase in the level of transmitted power to large load areas. BC Hydro chose eight-gas monitors for both technical and commercial reasons. In fact measuring the levels Locally no power generation plants were available with of all eight fault gases typically provides a more reliable sufficient power to support the regulation of system picture of transformer problems than can be determined parameters. The most obvious option was to lay new by monitoring a single gas such as hydrogen. The gas parallel AC connections but this could create serious chromatography system contained in the monitors has problems in terms of creating new system operating been tested and refined over the product’s history. Utili- conditions such as fault current levels beyond the design ties around the world are basing their transformer asset thresholds of the existing substation, increased risk maintenance strategies around these devices. of a cascade effect in the event of a failure that could cause widespread outages and loops flowing in strongly The installation of on-line DGA monitors in T1 resulting meshed AC connections. almost immediately in gas level alarms has stressed the need to conduct a detailed investigation of the cause of The technical and economical solution that was finally the problem. On-line DGA has allowed BC Hydro to take selected as the most appropriate consisted of a DC (Direct prompt and timely preventative remedial actions and to Current) link embedded within the AC network, which return their power transformer to service within a very connected two synchronous nodes over a short distance. short timescale. The DC option, in fact, allows for the precise, rapid control 60 Smart Grid to Enhance Power Transmission in Vietnam and adjustment of the transmitted power along the link, are being implemented in other regions including outside as well as enabling the regulation and stabilization of the the USA. One example of these applications, namely the parallel AC connections, without increasing the level of TRANSBAY project for PG & E in California, is presented short-circuits while introducing a sort of firewall between here, highlighting the main features and benefits related the two areas thus reducing the risk of disturbances and to the implementation of this type of system. outages propagating across large sections of the grid. The configuration of the transmission network system This solution was first introduced in the vast urban areas of around the San Francisco Bay is shown in Figure 42. New York and San Francisco, but now similar applications FIGURE 42: SAN FRANCISCO BAY AREA TRANSMISSION GRID Source: California Energy Commission, 2015, (15) Volume 1: Technical Analysis 61 FIGURE 43: SAN FRANCISCO TRANS-BAY PROJECT Source: Trans Bay Cable, 2014, (16) The goal of the Trans-Bay project was to eliminate bot- f. Inherent Overload Capability (10% continuous tlenecks in the overloaded Californian grid. New power overload duty and up to 25% for up to 4 hours) of plants were not and still cannot be constructed in this the selected technical solution; densely populated area, an issue further compounded by g. Dynamic Control of Reactive Power/support of the fact that there is no right-of-way for new lines or land AC voltage. The VSC converter is able to provide cables. This is why a ~90 km DC cable was laid across a large amount of reactive power with completely the bay as shown in Figure 43. The selected configura- independent control of the regulation of transmitted tion ensures more load serving capability than all the active power, as shown in diagram of Figure 44; other alternatives that had been considered. h. Reduced System Harmonics generation for full The following are the main benefits and specific advan- Compatibility with PG&E’s San Francisco Area tages provided by the selected solution: installed SVCs; and i. Enhanced Reliability, with fulfillment of all the a. Controllable Power – Exact power flow from Gen- criteria identified considering the N-1 and N-2 eration to Load as well as enhanced stability of the contingency analyses, applying standard criteria AC system. PG&E reported an estimated benefit defined by California ISO (including special crite- in economic dispatching of around 55 M$/year; ria for the Greater Bay Area) and WECC. b. Operational Flexibility; The total investment required for the implementation of c. Firewall Protection – AC system disturbances the link was approximately $450 million, which included: kept confined; a. Components costs; d. No Increase of Short-Circuit Current; b. Construction costs; e. Reduced System Line losses. PG&E reported a loss reduction of around 16 M$/year; c. Interconnection Costs at the two terminal stations; 62 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 44: VSC P/Q CAPABILITY CURVE Source: SIEMENS, 2013, (17) d. Land Costs During Construction; The Trans-bay project completed the Greater Bay Area transmission loop benefiting the entire Bay Area, since e. Mitigations and Development Costs; system security is increased significantly resulting in f. Financing Fees and related Costs; reduced power flow on existing Peninsula and East Bay lines, as shown in Figure 45, where the different dark g. Project and Construction Management; and graduation visually highlights the load level of the AC h. Start-up Costs. transmission system, before and after the placement of the HVDC link. FIGURE 45: GREATER BAY AREA TRANSMISSION SYSTEM LOADING CONDITIONS WITH AND WITHOUT HVDC LINK IN OPERATION Source: SIEMENS, 2013, (17) E. Identification of Viable Solutions for the Vietnamese Transmission Network E.1 Key Points Summary of solutions a. Planning and AMS basic strategies improve- identification ments: The aim is to drive transmission network expansion in order to overcome present network Vietnam is experiencing rapid growth in consumption and topology issues; a commensurate expansion and evolution of their energy b. State Estimation and on-line N-1 Security transmission network. This means that its Smart Grid Assessment: The aim is to have proposed on-line roadmap will need to be refined to include applications solutions for expected contingencies; improve that are not yet integrated within their existing systems. the real time knowledge of electrical system sta- tus and recommend best practice in preventive Therefore, a gap analysis has been performed in order and corrective remedial actions; to identify all the applications not yet integrated in the existing grid but which are fundamental to reach an c. Load-Frequency Regulation strategies adequate technological level in the transmission system improvements: The aim is to guarantee fre- for enabling a Smart Grid development. This analysis has quency stability and transient support by allocat- been carried out starting with those identified issues and ing sufficient primary reserve to overcome any challenges in conjunction with including the functional- power imbalance due to generation tripping or ities that a transmission utility should have installed. The changes in the imported/exported power levels; aim is to have a target operating model in line with the d. Protections System improvements: The aim is common current technologies and functionalities devel- to equip substations and transmission lines with oped in most of the world’s power systems. state of the art digital relays in order to protect against failures and coordinate their intervention With this approach in mind it is possible to position Viet- by means of inter-tripping logic systems (when nam on a timeline that highlights the technological gap required); that its transmission system has to span between its cur- rent operating model and the target operating model, as e. TLC system improvements: The aim is to sup- shown in Figure 46. port the development of the initiatives listed above. NPT’s current data communications network proj- This phase can be considered as a “transmission sys- ect should be complemented in order to enhance tem enhancement” and the following initiatives have the development of the above applications. been identified as basic building blocks: FIGURE 46: TECHNOLOGICAL GAP THAT VIETNAMESE TRANSMISSION SYSTEM HAS TO FILL Source: Authors 63 64 Smart Grid to Enhance Power Transmission in Vietnam This chapter includes the following: g. Voltage Stability, Profile and Support/Reactive Power Balance; a. A brief overview of the Vietnamese issues and h. Lightning Performance of exposed 220 kV lines; challenges, fully described in ‘Annex 2b’; i. SCADA & Remote Control Centers; b. A description of basic building blocks (named “pillars“) just mentioned, using best practices j. Time and cost reduction of asset maintenance; as articulated in the section on international k. Power Quality; and experiences; l. Interconnections with neighboring countries. c. A table of those Smart Grid initiatives identified as viable for Vietnam. In particular, this section aims to map the issues and challenges to the E.3 Transmission System enhancement: , described in paragraph ‘E.3’, and to the “pillars” pillars for building a Smart Grid Smart Grid solutions that will be described in the following chapter ‘F’. The Gap Analysis identified some functionalities and con- cepts that NPT and/or NLDC has to implement in the very E.2 Overview of Vietnamese issues short-term. These can be considered as the “pillars” for building a Smart Grid. This idea will be used again in the and challenges design of the “technical prioritization analysis” of Smart Grid initiatives, described in chapter ’G’. As stated in the previous paragraph ‘E.1’, developing nations like Vietnam require a “transmission system In this section these concepts will be described briefly, enhancement” phase before implementing Smart Grid using best practices as articulated in the international initiatives to ensure that the future transmission network experiences section in order to tailor some initiatives for is built on a solid enabling foundation. the Vietnamese context. The survey of international experiences has collected A paragraph will be dedicated to each pillar, except for best practices for the enhancement of transmission sys- “TLC system improvements” which will not be directly tems to provide a sound base for the development of investigated. In fact it cannot be considered as a single Smart Grid initiatives. initiative, but only as a key enabling feature of an exist- ing system to support other application development. If This chapter aims to identify all the proposed solutions the Vietnamese TLC system, in its present state or in the for the Vietnamese transmission network linking each to near future, is or will be adequate to support the imple- the particular issue being addressed. mentation and/or enhancement of initiatives like state estimation or primary load-frequency regulation, then no Transmission system enhancement initiatives will be further action will be required. described in paragraph ‘E.3’, while chapter ‘F’ is dedi- cated to Smart Grid Solutions. In this chapter the description of functional and organi- zational structure models of Transmission Utilities, as Firstly, it is worth summarizing all the issues and chal- described in ‘Annex 1’ will be referenced to indicate the lenges identified in the Vietnamese Transmission System functions that are required to develop each application (also confer ‘Annex 2b’). Those will be used to introduce and the eventual interactions between them. the solutions described in the following chapter ‘F’. The list of issues highlighted includes: E.3.1 Planning and Asset Management a. Network topology issues; System basic strategies improvements b. Short Circuit Level; In order to increase the resilience of the power sys- c. Miscoordination of Protection System; tem given the present network topology issues such as meshed HV networks and high level of short circuit d. Defense Plan improvements; values it is appropriate to adopt some simple solutions e. Load-Frequency regulation; involving Planning, Asset Management and System Operation functions. f. 500kV limited transient stability; Volume 1: Technical Analysis 65 First, from the analysis of the single line diagram of the power generators (based on, or connected through, Vietnamese system and from the information received power electronics) provide a negligible short circuit from NPT technicians it is clear that all of the 500/220kV power contribution. interconnections autotransformers are devices with a delta tertiary compensation winding where the The Vietnamese transmission network also has some main winding neutral is grounded. This reduces the reactors between busbars (acting as bus couplers) and single phase short circuit voltage drop, bounds the the devices and associated equipment (the reactor itself, zero sequence fault current to the faulted section but breakers, etc.) could be installed to solve some specific increases its amplitude. issues related to the short circuit currents exceeding the threshold of the equipment. Such reactors can be With the aim of reducing the single-phase-to-ground equipped with a bypass breaker in order to switch it on or short circuit current in those cases where three auto- off depending on the dispatching condition of the system transformers are installed in the same station, suitable (i.e. short circuit power and load flow). It is worth con- local automation systems could be implemented in order sidering that switching such reactors on or off through to keep two of them with neutral grounded, while the the bypass breaker could be controlled remotely or even third one remains ungrounded. This provision requires automatically, depending on the state of the station bay the installation of suitable breakers in between the neu- breakers. tral of the autotransformers and ground. Finally, since single pole reclosing is being used, an The Vietnamese network topology could lead to a very analysis of the operation statistics could lead to the iden- high fault current that could exceed the rated current tification of those overhead lines with many successful thresholds of their circuit breakers causing failures when instances of single pole reclosing. These lines should opening. For this reason the bus-bars of some stations be carefully considered for the application of the LSA. are operated separately resulting in a lower reliability of Furthermore the best location for LSAs can be decided the system contrary to the N-1 criteria. This happens on on the basis of analyzing distance relay records for the the 220kV network where most circuit breakers have incidence of faults. a rating capable of withstanding currents of 40kA. This limit is not particularly high as nowadays typical breakers On the other hand, if a high percentage of unsuccessful installed in 220-230kV networks around the world have single pole reclosing occurs, it could be a symptom of rated current thresholds of 50kA, or more. So, if the short a non-optimal selection of the neutral reactance associ- circuit level measured in most critical areas of the net- ated with the line side shunt reactors. work is less than the rated current thresholds of newer breakers, this may present the opportunity of swapping the breakers as described in the international experience E.3.2 State Estimation and N-1 Security (see D.2.2). This solution is applicable to openair substa- Assessment tions or hybrid ones. It cannot be applied to Gas Insulated The first enhancement to NTP’s network operation is the Switchgear (GIS). roll-out of a State Estimation and a modern state-of-the- art Energy Management System. NTP has undertaken Substitutions of breakers and small changes to the the modernization of their SCADA/EMS systems in all mechanical provisions for busbars and bays could the four Control Centers. The new system will meet the enhance their resilience to dynamic stresses caused by requirements addressed in this report and the findings short circuit currents. These provisions should be closely from the analysis of the recent incidents that occurred in studied and designed, but this technique has been suc- the Vietnamese Power System. cessfully applied in a number of substations across Italy. Note that very often busbars and bays are already over After the roll-out of the State Estimation algorithm, an designed from the point of view of mechanical resilience on-line Security Assessment Procedure should be imple- and thus these additional provisions are simple and mented. The procedure should be automated in order to cheap. Terna conducted some studies of the network and avoid Operator intervention in collecting and preparing successfully tested these provisions. data, running the simulations or collecting and analyzing the results. The procedure should start by automatically In the long term, with the installation of renewable collecting the most recent state estimation output, evalu- power generators (wind and solar) the higher levels of ating system response against a list of significant and short circuit power relative to the increase of the total credible contingencies and, finally, presenting the results power throughput becomes less critical since renewable to an operator-oriented interface. 66 Smart Grid to Enhance Power Transmission in Vietnam Since transient instabilities have been detected on the In order to create optimal primary and secondary regula- 500 kV backbones, a dynamic security simulation of the tion, studies and simulations must be conducted in order power system should be included in the Security Assess- to fine-tune the dynamic models to align them with the ment Procedure. The most credible triggering events, records of frequency and the responses of the Vietnam- such as breaker failures or 500 kV circuit tripping, could ese system. be repeatedly simulated on every new SE snapshot to ensure the system’s ability to withstand the transients caused by the contingencies/triggering events. E.3.4 Protections System improvement NPT’s current initiatives regarding the definition of basic The Operator will be able to change the operation of the specifications for protection and control systems being system from the optimized configuration to a secure installed in their new stations combined with the adop- one. This action should be based on the results and the tion of advanced IED together represent a step towards guidance of the on-line security assessment. system improvement and will help to resolve the problem of a miscoordination of the protection system (described The most updated power system models, from a steady in ‘Annex 2b.viii’). state and dynamic point of view, should always be pro- vided for the Security Procedure. Thus, the SCADA/EMS In the event that it proves to be insufficient, a detailed will allow the users to upload the models into the Security survey of all installed protection systems, especially in Assessment procedure with no significant restrictions. older stations is highly recommended. In this way, it will be possible to characterize and categorize all the installed The on-going new SCADA / EMS project (see paragraph protection systems, highlighting the eventual causes of ‘F.2’) will deploy a modern Energy Management System their malfunctioning or miscoordination and facilitate the which has an integrated Security Assessment feature. development of an effective intervention policy to either Thus the procedures should be accurately tuned in order repair or replace. to meet the simulation requirements above. Therefore, to reduce transmission network vulnerability to faults, as stated for Asset Management and Planning E.3.3 Load-Frequency Regulation strategies in paragraph ‘E.3.1’, it is important to assess both new improvements components that have to be installed as well existing The first step is to analyze the primary load-frequency reg- ones. In fact, putting together all the critical nodes of the ulation of the system based on the best set of hydropower network (i.e. old and new installed stations) it will be pos- units that contribute to this type of regulation by selecting sible to list the real categorizations of the problems expe- the best drop for each one. After this initial phase the per- rienced with protection systems and of devices where formance of the overall EVN system in terms of eventual there is a greater need for remedial intervention. inter-area power oscillations should be monitored. Furthermore, it is possible to improve the requirements The remedies, if needed, consist of reconfiguring the pri- of the protection system by developing an installation mary load-frequency regulation (set of regulating power strategy that will support consistent and incremental units and selection of their drops) followed by the sec- improvement of system reliability. For example it may be ondary frequency regulation. appropriate to copy successful strategies used in devel- oped countries by installing two completely independent According to international best practices, the largest protection systems at each end of a line, operating with number of the generators connected to the grid should different algorithms and provided by different vendors. participate in the Primary Load-Frequency regulation. This Both these devices would be completely independent of is the best approach to achieving a good primary regula- each other at both the hardware (e.g. cabling, case, etc.) tion. An exception to this prescription may be issued for and software (e.g. programming, algorithms, etc.) levels small generators, e.g. with rated power below the value and it would be enough if only one of them triggered the determined according to the size of Vietnamese power start of the protection logic. system, which could not guarantee the necessary perfor- mance for the primary frequency control or the suitable The cost of testing and proving two different devices for amount of primary reserve. the same function is an expensive proposition but not nearly as costly as the damaging effects of protection Additionally, a suitable Automatic Generation Control system malfunctions or miscoordinations on the whole (AGC) for secondary regulation should also be installed. transmission network. Volume 1: Technical Analysis 67 E.4 Problems-solutions mapping as can be seen from both Table 13 and Table 14 that some solutions solve more than one problem. Before providing a detailed description of individual Smart Grid initiatives, it is important to introduce them Over the lifetime of all the projects across the three time in connection with the problems they are intended to scales the complete integration of the solutions within resolve and to plan their development over a realistic the transmission system, properly leveraged (especially time frame. Table 13 and Table 14 aim to map the issues WAMS or SAS) could address a much wider set of issues. and challenges to the “pillars” , described in the previous paragraph, and to the Smart Grid solutions that will be Using WAMS as an example of this approach; the instal- described in the following chapter ‘F’. In some cases the lation of PMUs at key points of the transmission network simple “pillar” implementation is required while in others could facilitate, in the medium/long term, the develop- only a Smart Grid initiative can solve the problem. ment of Defense Plans based on early warnings based on WAMS measurement. This would be possible only The aim of each solution is to solve the associated prob- after a full integration of WAMS with the transmission lem and will be described in the following chapter ‘F’ and, TABLE 13: ISSUES-SOLUTIONS MAPPING ISSUES ISSUES CHARACTERISTICS PILLARS SMART GRID SOLUTIONS • Planning and Asset • Static Var Compensators Management Network topology issues • Network highly meshed • Dynamic Thermal Line strategies Rating improvements • Planning and Asset • Fault current could exceed the Management Short Circuit Level • Not Applicable • rated current of the breakers strategies improvements • Outages due to protections failures Miscoordination of • Interference and electro-magnetic • Protection System • Power quality monitoring Protection System compatibility issues on secondary improvement system signals • If the N-1 security criterion is not • Substation Automation fulfilled an SPS remedial action is • State Estimation System Defense Plan improvements necessary • N-1 on-line Security • Wide Area Monitoring • The security assessment is performed assessment Systems off-line not on-line • At present this type of regulation is • Load-Frequency Load-Frequency regulation achieved by using only one of five regulation strategies • Not Applicable single hydro power plant at a time improvements (AGC) • State Estimation 500kV limited • Wide Area Monitoring • High North–South power flow • N-1 on-line Security transient stability Systems assessment Voltage Stability, Profile • State Estimation • Wide Area Monitoring and Support/Reactive • High North–South power flow • N-1 on-line Security Systems Power Balance assessment • Static Var Compensators Lightning Performance • Surge Line Arrester installation • Not Applicable • Lightning Location System of exposed lines without a Lightning Location System Source: Authors 68 Smart Grid to Enhance Power Transmission in Vietnam TABLE 14: CHALLENGE-SOLUTIONS MAPPING CHALLENGES CHALLENGES CHARACTERISTICS PILLARS SMART GRID SOLUTIONS • Substation Automation System • Improve the • Wide Area Monitoring Systems Monitoring and remotely monitoring, • Telecommunication system • Metering Data Acquisition System control the network observability and improvements • Geographic Information Systems control of the network • On-line Dissolved Gasinoil Analysis for Power Transformers Time and cost reduction • Improve the efficiency • Not Applicable • Fault Locator System of asset maintenance of the system • Improve the quality of Power Quality • Not Applicable • Power quality monitoring system the system • State Estimation • N-1 on-line Security • Interconnections with • High Voltage Direct Current Interconnections assessment neighboring countries technology • Load-Frequency regulation strategies improvements Source: Authors operation system as well as the System Operation staff system problems they aim to solve. Their positioning acquiring a complete understanding of this technology. within the different time horizons will be investigated in the “technical prioritization analysis” of Smart Grid Therefore, Table 13 and Table 14 are very useful for pro- initiatives (see chapter ‘G’), after a full description of the viding a basic introduction to all the solutions and to map possible developments and benefits of each initiative, the initiatives with the specific Vietnamese transmission which will be performed in the following chapter ‘F’. F. Description of Smart Solutions Identified F.1 Key Points Summary of Smart v. Wide Area Monitoring Systems (WAMS); Grid Solutions vi. Dynamic Thermal Circuit Rating (DTCR); Vietnam has already undertaken some steps towards vii. Fault locator system (FLS); and the development of Smart Grid technology across their viii. Geographic Information Systems (GIS). infrastructure. In particular in March 2012 ERAV, the Elec- tricity Regulatory Authority of Vietnam, promoted and The aim of this chapter is to describe all the Smart Grid developed a “Smart Grid Project and Implementation solutions identified in paragraph ‘E.4’ and for each one to Roadmap” officially approved in November 2012 (deci- point out if; sion n° 1670/2012/QD-TTg). The roadmap consists of three phases (short, medium and long-term) and covers a. A similar solution has been already proposed by both the transmission and distribution networks. the existing Vietnamese Smart Grid roadmap. If this is the case then the Vietnamese solution will In January 2013 the Minister of MOIT established the be briefly described; and Smart Grid development Steering Committee at which 15 members from the different companies involved in b. It is a new opportunity in which case the pro- the electrical sector regularly meet. posed solution will be based on international best practices as previously described. The Smart Grid projects for the Vietnamese transmis- Therefore, this chapter summarizes the technical sec- sion network sit under the umbrella of “Decision n° tions of the proposals for the Vietnamese transmission 1670/2012/QD-TTg” . According to the classification network and is aimed at commercial and business level assigned by the Steering Committee, some initiatives decision makers. The first two sections provide a brief are included in the first phase of the Smart Grid road- description of the enhancements to the SCADA  /  EMS map (short-term) and will function partly as pilot projects system and the telecommunications infrastructure for while the full deployment of the solutions will have a the transmission grid. These are necessary pre-requisites medium-term perspective. for the development of a reliable and efficient electrical transmission system and, as such, are outside the scope Thus, it is worth recapping the Smart Grid applications of a typical Smart Grid roadmap. already in progress or planned for the Vietnam Power Transmission Network: This is followed by a presentation of the Smart Grid initia- tives proposed for the Vietnamese transmission network a. At the time of writing this report the following are and includes the following: in progress: i. Substation Automation System; a. Substation Automation System (SAS): This section describes the NPT project already under- ii. Information System for Operation and Super- way and makes recommendations to optimize vision; and the benefits of this solution especially with iii. Wide Area Monitoring Systems (WAMS)— regard to interoperability and telecommunication Pilot project. system improvements. b. Roadmap: b. Wide Area Monitoring System (WAMS): The main focuses are: i. Substation Automation System upgrade; i. The PMU positioning strategy emphasizing ii. Communications Infrastructure for Transmis- the importance of monitoring not only the 500 sion and Substations; kV network but also the 220kV network; iii. Upgrade Information System; ii. The brief description of possible WAMS appli- iv. Metering Data Acquisition System; cations useful for the Vietnamese context 69 70 Smart Grid to Enhance Power Transmission in Vietnam such as voltage stability monitoring, oscillation i. Dynamic Thermal Circuit Rating (DTCR): The detection as well as monitoring. main techniques used for implementing this solu- tion are presented. The steps required to develop c. Lightning Location System: This presents a a DTCR project that uses all the different tech- guideline for the development of this system high- niques are also proposed. lighting the benefits with a particular focus on the installation of Transmission Surge Line Arresters. j. Geographic Information Systems: This cannot be considered as a single Smart Grid initiative in d. Static Var Compensator: The main benefits of its own right but needs to be seen as a means this type of system are identified with reference of enhancing other applications. Its benefits will to possible applications within the Vietnamese impact different Transmission Utility functions, transmission grid. The installation of the SVC sys- like System Operation and Asset Management. tems is recommended in order to better regulate the voltage profile of the 500 kV transmission k. Metering Data Acquisition System: Before lines and, with suitable control loops properly commencing an initiative to acquire meter data integrated with the WAMS applications, to sig- remotely it is important to carefully consider nificantly increase the damping of the system the regulatory implications and aspects and to during transients particularly in cases of inter-area develop an appropriate protocol for the interface oscillation. The use of re-locatable SVC systems with the electricity generation function in the is recommended as a possible solution to ensure event of critical situations. This application rep- the maximum flexibility for this kind of application resents an enabling technology for the develop- in the light of the rapid development of the trans- ment of the electricity market. mission system and the need to provide timely, location specific support for substantial changes For the various initiatives different levels of detail will be and re-configurations of the grid. assigned, depending on their complexity, the criticality of the problems they aim to solve, the existence or not of a e. High Voltage Direct Current technology: The Vietnamese project that will need analysis and the state main benefits of this technology are presented, of development of the project itself as well as the areas highlighting the possible fields of application in which it can be exploited. In particular, the applications from a long-term perspective. The technical and that may have a wide ranging and positive impact on the economic benefits that can be achieved are dis- transmission system will be significantly detailed. cussed for some specific applications, such as the interconnection with neighboring countries Finally, in chapter ‘G’ each solution will be located on and the supply of large congested loading areas a technology driven timeline, specifying whether it is a with high levels of short circuit currents and loop- short, medium or long term initiative and, if necessary, flow issues. indicating the prerequisite steps prior to starting it. In this f. Fault Locator System: The main benefits of this way it will be possible to design a realistically phased technology are investigated in the context of Smart Grid roadmap. asset maintenance in order to deliver significant time and cost efficiencies. g. Power quality monitoring system: The ben- F.2 New SCADA/EMS system efit of this type of system is analyzed primarily in terms of improving power quality levels which Before starting a detailed analysis of the proposed Smart helps to optimize investments in installations Grid solutions it is useful to briefly describe the on-going aimed at increasing resilience to voltage dips and project of the SCADA/EMS implementation. This system, increasing the ability to promptly identify mal- in fact, will be the focal point for all the Smart Grid applica- functioning protection systems. tions and will be the point of interaction and information exchange, both for acquiring data and providing results. h. On-line Dissolved Gas-in-oil Analysis (DGA): The main benefits of such technology are pre- The purpose of this project is to implement a hierar- sented with recommendations to equip all new chical SCADA/EMS system comprised of a set of fully transformers with this type of device. Their use integrated, geographically distributed and redundant with the existing transformer fleet will require Supervisory and Control Systems to support the National the identification of the most critical and valuable Load Dispatching Center in the operation of the country- ones that need to be protected. wide bulk interconnected Electricity Power System. The Volume 1: Technical Analysis 71 SCADA/EMS will have four different sites, including the All of these data are collected, achieved, and maintained, National Load Dispatch Centre (NLDC) and the North- always ready for operation, planning, and maintenance ern Regional Load Dispatch Center (NRLDC) which are activities as well as large-scale applications. Therefore, both in Hanoi, the Central Regional Load Dispatch Center such initiative plays a fundamental role in supporting and (CRLDC) in Da Nang and the Southern Regional Load Dis- exploiting Smart Grid solutions described in the following patch Center (SRLDC) in Ho Chi Minh City. paragraphs. The new SCADA/EMS system will include several func- tions, amongst which are: F.3 Telecommunications Infrastructure for the a. A Graphical User Interface (GUI); Transmission Grid b. A situational awareness system; In order to collect the data to be used in the new SCADA/ c. An advanced alarm management system; EMS system (NLDC), as well as to support remote con- d. A real-time and historical trending application; trol of the substations of the electrical network (NPT), the development of a communication backbone connecting all e. A load shedding and restoration system; the substations under NPT management is a fundamen- f. Automatic generation control and dispatch modules; tal requirement. The total expected investment is about USD 2,000,000 and includes the equipment to interface g. Short-term load forecasting; with STM-4 (622 Mbps) communication links. A quick h. Market operations interfaces; sketch of the tentative solution is presented in Figure 47 . i. Tools for network security analysis; Even though a telecommunications infrastructure is j. Dynamic security assessment; not usually considered part of a Smart Grid program in mature and highly interconnected networks since it is k. Voltage stability and transient stability analysis; and usually already installed as a backbone system, it is a l. An operator training simulator. pivotal enabling technology for the development of a reli- able and efficient electrical system. Therefore the current NLDC plans to conclude this project in 2015. data communication infrastructure initiative can be con- sidered as one of the steps in the Smart Grid roadmap Even though some functions can be considered basic for a fast growing and developing country like Vietnam. for mature and highly interconnected networks, a SCADA/EMS system at the National Load Dispatching Centre certainly FIGURE 47: NEW TELECOMMUNICATION INFRASTRUCTURE represents a pre-requisite for the develop- ment of a reliable and efficient electricity transmission system. Therefore it must be considered as one of the first steps in the Smart Grid roadmap for the fast growing and developing country of Vietnam. For the development of the Smart Grid roadmap it is also worth to consider that NPT is currently building a technical man- agement software (management device parameters, line, reporting, monitoring equipment, laboratory  ...). This initiative aims to increase power system opera- tional efficiency focusing on solutions for unmanned substations management and operation, remote control and switching centers. This software provides users with simultaneous access to a large amount of Source: Authors real-time information and historical data. 72 Smart Grid to Enhance Power Transmission in Vietnam The main purposes of this upgrade project of the Infor- It differs from the telecommunication network currently mation System are: being implemented for the exchange of information between the transmission substations and NLDC/NPT a. To connect directly to NPT’s substations for control centers, as the former will connect customers acquiring data (Analog, Status information at and generation plants outside the EVN boundary. the substations and metering data) and provid- ing data to PTC’s Information Systems and data The project has not yet been started and at present no backup for NLDC’s SCADA system; deadlines have been agreed for its completion. However, NLDC considers the project of the greatest importance b. Integrating WAMS, DTCR, FLS in NPT’s and and is pushing for a quick approval. The infrastructure will PTC’s Information Systems; be based on an optical fiber backbone. c. Integrating advanced functions such as load flow, stability limit, transfer capability of transmis- It is likely that the new telecommunication network will sion network in real-time (on-line), fault, off-line be used for enabling different markets including the ancil- stability, etc.; lary services where considerable improvements can be made. In fact the actual management of primary and sec- d. Exchanging information and data with other parts ondary network energy reserves must be improved and of the system in Vietnam’s Electricity Market; fine-tuned. and e. Allowing the registered users of NPT and PTC As already stated regarding the primary telecommunica- to easily access necessary information from tion infrastructure for NPT’s transmission grid, the new anywhere using Web services with a high secu- Wide Area telecom network itself cannot be consid- rity level in accordance with international data ered part of a Smart Grid program in a mature and open security standards. energy market but it is an essential enabling technology for developing an integrated Smart Grid in Vietnam. These objectives highlight just how pivotal the Informa- tion System is as the load-bearing structure of all the The problem of connecting players outside the EVN Smart Grid initiatives that are required for the Vietnam- boundary will be described in paragraph ‘F .14’, where ese system and that will be described in the following the Metering Data Acquisition System initiative will be sections. In this report the design of the new IT sys- investigated. As discussed in the international experi- tem will be assumed to be consistent with a modern IT ence section (see D.2.9) on metering, the requirement system, both in terms of having a fully enmeshed and of measurability is the basic condition and indeed a key resilient data communication capability complete with performance indicator for the admission of each power services for storing and processing data and the ability plant to the electricity market. to support all the Smart Grid applications as required. For those initiatives that have a particular impact on pre- existing IT systems (like Automation and Tele-Control for F.4 Substation Automation System Substations or WAMS) special needs will be underlined or the specific necessary structures and devices will be Fully digitized substations, remote terminal units, remote described. operations and supervision are basic functionalities of a modern power transmission network and they are the Before starting with a description of Smart Grid initia- pre-requisites for further developments towards a Smart tives, it is worth focusing on a specific path for improving Grid. Towards this aim Vietnam is implementing an initia- the data telecommunication systems in the context of a tive to modernize the 220 and 500 kV electrical substa- Wide Area Network for Market Development. tions of the transmission network. The project has been in place since 1999 and is now in its third phase and its main characteristics will be described in the next section F.3.1 Wide Area Network for Market (F 4.1 below). Development The construction of a Wide Area telecommunication net- F.4.1 NPT Substation modernization work for connecting all the players that participate in the electrical market is seen as a discrete standalone project initiative in Vietnam. In the first phase NPT had to deal with: Volume 1: Technical Analysis 73 a. Digital protection and control using legacy serial will be able to exchange data by means of a direct link and hardwired connections; using ICCP protocol as shown in Figure 48. b. Problems with interoperability between multiple The protocol IEC 60870-5-101 has been chosen for its manufacturers’ IEDs. compatibility with legacy systems and supports the inte- gration of the SAS of the old substations as they cannot In the second phase which was started in 2003 EVN currently support IEC 60870-5-104 (the newer and more issued a specification for SAS aimed at improving flexible protocol). In the deployment of the SAS project it IED compatibility. UCA2, Modbus TCP , DNP TCP, and is important to install RTUs that support a dual configu- IEC 60870-5-104 were chosen as substation LAN com- ration capable of supporting both IEC  60870-5-101 and munication protocols between Host Computers and IEDs IEC 60870-5-104. This will be a useful starting point for or NIM (Network Interface Modules). The IEC  60870-5- possible future developments as it will allow a full migra- 101 protocol was chosen to move data from a substa- tion to the IEC 60870-5-104 protocol for all substations. tion’s realtime database to the existing SCADA system. This NPT project is basically comprised by two The currently ongoing third stage will see the installation interventions: of digital equipment and the adoption of the IEC 61850 protocol for LAN communications. The IEC  60870-5- a. Substations’ modernization process (upgrade of 101/104 will be used instead for communication between old substations and building of a wide number of the Substation Automation Systems (SAS) and the new ones); Remote Centre, i.e. the Information System for Opera- tion and Supervision of NPT networks. b. Building of Remote Control Centers for unmanned substations. The project will oversee the construction of 236 new The expected benefits of this system concern different substations and the upgrading/revamping of another aspects and they will be fully achievable if the substa- 183. The Information Centre will support remote opera- tions’ modernization process will be conducted in synergy tion of the substations and the first instance of remote with building of Remote Control Centers for unmanned operations capability will be in place by the end of 2015. substation. Remote Control Centers, in fact, constitute a prerequisite to exploit at best SAS equipment in electrical NLDC’s SCADA/EMS System and NPT’s Information Sys- substations. tem will collect information in parallel from the field and FIGURE 48: NEW NLDC SCADA/EMS AND NPT INFORMATION SYSTEM Source: NPT-World Bank, 2013, (18) 74 Smart Grid to Enhance Power Transmission in Vietnam Looking to SAS benefits, this system substitutes physical F.4.2 Recommendations for continuous displays for Substation Online Metering and Alarm with improvement strategy easy to understand and operate HMI in terms of: The outcomes of the second phase are the basis for a. Alarm Annunciation; achieving communication interoperability. The aim is to have seamless communication within the power sys- b. Trending; tem based on an open communication protocol not only c. Substation Logs; and between the IEDs but also for inter-substation communi- cation and on the link between substations and control d. Display Generation and Maintenance. centers. The last point to be considered and perhaps the most The activity of interoperability testing and standards anal- challenging is the development of a flexible HMI capable ysis has to continue during the whole implementation of supporting display configuration as this will require sig- process as well as into the future. Future developments nificant investment and effort. need to remain mindful of the risk of proprietary lock-in if there is an over reliance on a single vendor or standard. Furthermore, the SAS Historical Information System This could happen when system upgrades involve high (HIS) will be provided to store any data item at 1 second costs due either to commercial or technical constraints. intervals and to maintain the entire data set on the hard disk, for real-time on-line access, for a period of at least To minimize such risks, recommendations for upgrades 2 years. and future developments must be unambiguously based on best practices and offer the most flexible, open stan- Finally, the SAS implementation is assumed to lead to: dard architecture as well as effective risk mitigation strat- egies. These recommendations should provide a direct a. Faster system integration with IED interoperability; path for the simple definition of future projects, thus b. Reduction of copper cabling and hardwiring (all avoiding the most common “tricks and traps” and other control and protection cubicles will be installed in lock-in mechanisms used by manufacturers to reduce a outdoor cubicles and /or bay housings); customers’ freedom of choice. i. GOOSE for peer-to-peer data exchange; and Moreover, from a technical point of view, each upgrade ii. Outdoor cubicles adjacent to feeder or bay. must be evaluated on the basis of not only the target device but also in terms of the impact that this action has c. Reduction of system malfunctions by nearly 50%. on all the other devices and systems connected to the target device i.e. in a word, interoperability. Whilst the last point above suggests that system mal- functions will be reduced simply by deploying SAS, it is Thus, amongst other topics, the correct alignment of not completely correct. In fact, the larger the number of devices for NPT’s needs and goals will be a key factor devices and components installed the greater the likeli- of success. For this reason it is crucial to evaluate the hood of failure somewhere in the chain and this fact must features of any proposed systems, devices or equipment be given due consideration. It is probably more accurate especially in terms of: to say that the implementation of SAS will significantly reduce fault finding times thus decreasing the mean time a. Open standards; to repair. b. Performance adequacy; Among all the Smart Grid initiatives SAS is definitely c. Feasibility of upgrades; the one whose implementation has reached the most advanced stage. The choices made, in terms of technolo- d. Worldwide presence; and gies and development strategies, and the anticipated e. Vendor support. benefits compare favorably with international best prac- tices (see D.2.6). However, it is worth taking account of F.4.3 Telecommunication system the key points to be monitored in the SAS project devel- improvement opment process in order to ensure a successful deploy- ment and to apply a continuous improvement strategy Another fundamental aspect of the SAS project is the for the lifetime of the project. telecommunication system improvement that may be Volume 1: Technical Analysis 75 required for an extensive deployment of this application. The Vietnamese case involves a significant number of Different levels of implementation of a SAS project imply completely new devices. Thus, it is not worth limiting the increasing investments in the telecommunication sys- performance and flexibility of the system by accepting tem. It is possible to identify four levels of telecommu- the constraints imposed by current and legacy technol- nication system development related to correspondingly ogy. Instead the installation of new substations and the more complex levels of SAS project deployment: development of the TLC system should be viewed as an opportunity to deliver a high technical standard of data a. Remote control (alarming): Which entails the communications for GOOSE deployment. lowest level of performance required of the tele- communication system; The communication between substations is a significant opportunity to develop advanced plans for system opera- b. Remote monitoring (components diagnos- tion, especially for emergency situations. The use of tics): Here the telecommunication system has to GOOSE and therefore a lower requirement to exchange support a larger data stream due to the exchange information with the control center, could allow the of all the measures necessary for real-time sub- development of more flexible system operation plans. station monitoring; For example the designs and strategies for restoration c. Communication between substations: In this the communication between substations could include case the meshing and resilience required of the fewer constraints regarding selected paths thus facilitat- telecommunication system is more demanding; ing faster and more reliable recovery strategies. d. Monitoring of renewable generation: This is Therefore, in the SAS project the development of the last step in a SAS project and requires an GOOSE might be one of those Smart Grid applications additional layer of interconnectedness of the tele- for coordinating the development of the different roles communication network. This development will of the transmission in an efficient way. System opera- be useful for different aims like communications tion has to investigate those functions that could exploit of real-time forecasts, remote control of wind communication between substations. The planning has generation, etc. to accommodate an appropriate telecommunication sys- tem enhancement in order to support such functions and As stated before, one of the goals of the SAS imple- ultimately asset management has to deal with the instal- mentation is the adoption of GOOSE for peer-to-peer lation of all the required devices. data exchange. This means that the project in Vietnam will require the third level of telecommunication sys- Equally, it is important to underline that the creation of a tems improvement development as per the list above, highly resilient and reliable communication infrastructure i.e. item (c). Before doing this it is important to be cer- between devices using GOOSE is really challenging. This tain of having achieved communications between all the requires special attention on creating the communication substations and the control center both for control and architecture at the beginning of the project and involves a monitoring. dedicated network design phase for the selection of the network components, Ethernet interfaces and the IEDs Moreover, before deciding the level of meshing required themselves. Moreover, extensive interoperability tests of the telecommunication system to support GOOSE, it are needed to ensure devices from multiple vendors is fundamental to decide the types of plans (i.e.: defense work together smoothly. plans, load shedding, generation shedding, etc.) NPT and NLDC want to manage with this application and which Finally, the SAS project could be upgraded to include substations will be involved. This approach will be useful the monitoring of renewable/distributed generation. This in dictating the improvements to the telecommunication upgrade not only represents another level of complexity system in those areas likely to be affected by this type of in the development of the telecommunication systems application, thus concentrating investment only on criti- but also poses the technical challenge of achieving data- cal nodes of the network. exchange between the target devices and the distribu- tion network, where most of the renewable/distributed The Vietnamese case differs from those situations with generation systems are connected. This issue could some transmission systems (discussed earlier in D.2.6), also be faced by the Metering Data Acquisition System, where it was decided to communicate with the control described in F.14, where again the interface is between center to exploit the existing TLC network and therefore the transmission and distribution network. to use GOOSE only for intra-substation communications. 76 Smart Grid to Enhance Power Transmission in Vietnam F.5 Wide Area Monitoring System c. The achievement of advance system knowledge with correlated event reporting and real-time sys- The main cause of wide-area disruptions in the present tem visualization; NPT network is due to the relatively long 500 kV trans- d. The promotion of system-wide data exchange with mission line between Hoa Binh and Ho Chi Minh City, a standardized synchrophasor data format; and which is susceptible to voltage and angle instabilities when there are variances in load and generation sources. e. The validation of planning studies to improve sys- tem load balance and station optimization. Synchrophasor technology provides observability of the status of the power system to operators in real time, Over the mid-term time scale these predicted benefits which facilitates the calculation of the maximum loading could be achieved by successfully exploiting the WAMS condition for each system bus connected to the trans- project, which has to cover as much of the transmission mission network. Furthermore, preplanned corrective network as possible. The NPT’s pilot project may be a actions can be taken to minimize the risk of wide-area good starting point to study the best way to develop disruptions and increase the power transfer capability of the WAMS project on a larger scale and in particular to the system. The availability of a high-speed, high-band- test some functions and applications before deciding to width network architecture makes synchrophasors ideal implement them across the system. for this application. Thus, it is important to define a development strategy that could be divided into three main steps; F.5.1 NPT pilot project Towards this end NPT has developed a customized a. PMU devices selection and their positioning; solution for wide-area measurement that uses the syn- b. Communication system improvement; and chrophasor functionality within the installed IEDs. In par- ticular the HMI solution consists of several applications c. WAMS applications implementation. implemented for specific uses; F.5.2 PMU devices selection and their a. Desktop application for calculating the real-time positioning strategy power transfer capability of the system and to pro- vide alarming based on thresholds set by the user; PMU positioning strategy is fundamental to achieving effective observability of the dynamic behavior of the b. MATLAB application for migration of synchro- network. The installation of PMUs in all 500kV substa- phasor data to a programming environment for tions under NPT’s management will greatly improve the performing complex calculations; ability to monitor the long 500 kV transmission lines in c. Web application that provides access to the data terms of voltage and angle instabilities. remotely through a secure Internet connection; and However, to achieve complete system observability it d. Office application that provides a data-link inter- will be necessary to extend the real-time system to the face to the plant information database. wide-spread 220kV network for which it will be vital to develop a PMU positioning strategy. Only a few PMUs have been installed so far and the WAMS project for the entire 500 kV network is currently To this end, the international experience (see ‘D.2.7 .1’) considered as a project with a mid-term time scale and a could serve as a useful benchmark for developing an projected conclusion sometime in 2022. appropriate PMU positioning strategy. In fact, even if complete system observability may be impossible to The project aim is to install PMUs in all 500kV substa- achieve, it should be possible to focus successfully on tions under NPT’s management [2] and the expected monitoring the most critical portions, i.e. areas subject benefits are; to specific events (e.g. line trip with possible cascading) or phenomena (e.g. voltage collapse, oscillations) which a. Increased system loading while maintaining ade- may jeopardize system stability. This is true not only for quate stability margins; the 500kV network but also for the 220kV system. b. Improvement of operator response time to sys- tem contingencies, such as overload conditions, Before detailing the PMU positioning strategy, it is worth transmission outages, or generator shutdown; making a few observations on the choice of the models Volume 1: Technical Analysis 77 of the device to be installed and the related issues. In Another type of analytical criterion is the phenomenon- order to obtain reliable results from applications that oriented positioning technique which focuses on phe- will use PMU data it will be necessary to ensure high nomena affecting specific bus-bars or the system as a module and phase performance, which depends on time whole. In the first case phenomena such as voltage col- synchronization accuracy. So, the first step is to decide lapse or out-of-step are considered. Since the affected the required measurement accuracy and, consequently bus-bars are already known, the purpose is to detect the appropriate PMU models to be installed. While inter- those that are worst affected. In the second case affected national experience could once again prove a good ref- bus-bars are unknown and must be selected and typical erence point, it has to be said that the technology has phenomena are network islands or inter-area oscillations. advanced since then and the latest commercial products In this technique several different approaches based on offer far more satisfactory yields, especially in terms of dedicated network indices have to be investigated and synchronization accuracy. the results merged. Possible classes of indices are volt- age-related, oscillation-related and islanding-related. In this phase not only operation and planning but also asset management functions must be involved. This col- laboration could make a significant contribution to choos- F.5.3 Telecommunication system ing the right devices to be installed and, above all, it must improvement consider if substitutions of other equipment are neces- The telecommunication system is crucial for the develop- sary. For example, voltage and current transducers have ment and effectiveness of WAMS. PMUs, in fact, acquire to be very precise so CTs and VTs must have a high accu- and send data with quite a high sampling rate (e.g. 50 racy class (possibly 0.2%). So, if CTs and VTs are quite times per second). This data (measurements, time old and/or not very precise, it would be better to verify stamp, and the other status information) is formatted this first and substitute them, if necessary, before con- according to the IEEE C37 .118 standard and continuously necting a PMU. Otherwise the data gathered will have a transmitted to a central server. high sampling rate and good synchronization but remain extremely inaccurate in terms of the module and thus This requires a very high-reliability, high-performance prove completely useless for the monitoring and control redundant communication (e.g. multiple dedicated links) applications that use them. system compliant with the IEEE standard. Following the decision about the most appropriate device Moreover, all of the data acquired by PMUs must be models the next task is to select the best location for stored on WAMS servers called Phasor Data Concentra- the PMUs. One of the best ways to do this is by using tor (PDC). A PDC is responsible for processing streaming heuristic-analytical criteria, in order to maximize the oper- time-series data in real-time, making it available for the ating value of the measurements. applications that use them. The number of PDCs to be installed, their locations and design must be accurately The operators’ experience will be especially helpful in planned, taking into account both needs and perfor- pointing out some heuristic criteria (e.g. proximity to mance required by the WAMS system, the number of large generating units, known bottlenecks, borders, etc.) PMUs installed, the measurements required and the that could help determine the most suitable location to structure of the telecommunication system. install PMU, especially in the 220kV network. Finally, this huge amount of data must be managed in On the other hand the development of an analytical posi- an efficient way and is entirely reliant on the IT system. tioning algorithm should also be taken into account as In particular it has to guarantee fast access to real-time this aims to find the places in which PMU installation data and to the measurements acquired in the near past could improve observability for event identification, oscil- (few hours). It is worth storing older data, even if it is only lation detection, angle, voltage and frequency stability required on a less critical basis both in terms of time to monitoring. access and the sampling rate. If any alarm management application using PMU data is implemented, it would be The first type of analytical criterion is event-oriented appropriate to develop a dedicated storing facility for the positioning technique (e.g. flag node criterion) and its events identified by the trigger of alarms in order to allow aim is to find those bus-bars most affected by any kind of real-time on line access to them. perturbation between power systems, combining sensi- tivity and selectivity of the monitoring facility. 78 Smart Grid to Enhance Power Transmission in Vietnam F.5.4 WAMS applications implementation The first condition is the normal system operation behav- ior, when voltage and current phasors change at a very WAMS is a key Smart Grid application because its slow rate and as such may be regarded as negligible. The data provides the basic raw input for a large number latter is the operating condition when a voltage collapse of advanced functions serving network operation and occurs. Every increase in the source of the transmis- control. NPT has already planned to develop advanced sion line is not reflected by any increase of the complex synchrophasor applications and functions for wide-area power at the receiving end, even though voltage and cur- real-time control actions such as undervoltage load shed- rent phasors vary significantly over time. ding of noncritical loads, contingency-based remedial action schemes, automatic generation tripping, switch- The SDI algorithm is proposed as a voltage stability moni- ing of shunt capacitors and system islanding detection. toring feature but it could trigger corrective actions, like under voltage shedding, once implemented as the trigger All of them will be extremely useful but there are further (or part of it) logic of an under voltage load shedding relay. applications that can use PMU data to deliver improved monitoring and control of the Vietnamese transmission Although SDI is maybe the simplest implementation network. In the main these applications are oscillation index, it is not the only voltage instability predictor based detection and monitoring, phase angle monitoring, on phasor measurements. There are other algorithms and voltage stability monitoring, event detection and man- mathematical models developed for voltage stability moni- agement, alarming, backup and integration for SCADA toring, in most cases based on Thevenin equivalents (e.g. system. Voltage Instability Predictor – VIP, VIP++ [17], [18]). The pre- cise methodology and the prediction algorithm to be imple- In the following section the two most significant applica- mented for voltage instability monitoring is a matter that tions will be described briefly, suggesting possible tech- should be investigated further taking account of the particu- niques and implementation strategies to apply as well as lar Vietnamese issues and the requirements for EMS. underlining their added value. F.5.4.2 Oscillation detection and monitoring F.5.4.1 Voltage stability monitoring Another key application of the wide area synchronized ‘Annex 2b.iii’ describes the Vietnamese voltage stability system consists of a real time and off-line identification issues. In order to deal with this problem it is proposed of oscillatory behaviors. As highlighted in the WAMS that a WAMS based application for voltage stability moni- experience (see paragraph ‘D.2.7 .2’), the identification toring be developed. of unstable modes and the knowledge of their damping made it possible to determine the degree of stability of In the literature on the subject there are many examples the operating condition. The subsequent analysis of the of Wide Area Measurement based voltage instability participation factors of such a condition can suggest the detection algorithms. PMU measurements have been appropriate countermeasures that will need to be imple- used for voltage instability monitoring because of their mented [5]. greater precision rather than for their time-synchronization. Voltage stability, in fact is more a local than a network wide There are lots of techniques that are available for stabil- phenomenon, as it stems from the reactive power bal- ity monitoring and include nonparametric, parametric and ance at the busbar where the voltage collapse occurs. subspace methods, maximum likelihood estimation, etc. All of them aim to identify weakly damped oscillatory An effective voltage instability predictor is the S-Differ- behaviors, mainly inter-area, with a particular focus on ence Index. This index is based on the variation of com- the time at which these dynamics took place and their plex power ) at the receiving end of a transmission line trend. All these techniques are usually fed by significant between two successive samples of the voltage stability data from the power network such as active power flows algorithm. The complex power variation at receiving end or system frequency, where the power spectral density of transmission line can be estimated as: of the electromechanical modes is greatest. These measures have merits and disadvantages that are often complementary and it is for this reason that the use The variation can equal zero both when voltage and cur- of more than one method not only serves to validate the rent variations are negligible, or when the two terms of various improvements, but also helps to better validate the above sum have same absolute value and a phase the information obtained. difference of radians. Volume 1: Technical Analysis 79 A proper implementation of these algorithms will facili- Moreover, the decision regarding the number of PMUs tate full monitoring of electromechanical phenomena as to install as well as their location in the network and well as benefitting the daily system operation activities other related factors will determine the overall impact on by providing thorough and up-to-date measurements for the telecommunication system. This must be carefully evaluations and to improve the knowledge of the system considered to understand the required improvements to dynamics. support the WAMS implementation. Furthermore, post-event analysis of the results obtained The NPT’s pilot project is a good starting point, espe- by the application of these techniques, both of single cially for applications and functional testing, but in order events (contingencies, relevant oscillations, etc.) and to develop the WAMS project on a larger scale over the of long sequences of events, could help to identify the mid-term time scale the most crucial step is an accurate characterization of the dynamic behavior of the Viet- analysis phase focusing on all the issues described above namese transmission system and increase awareness and involving all the TSO functions impacted by this kind of transient stability assessment. Towards this end it is of initiative. worth highlighting the importance of statistical analysis of these results (see paragraph ‘D.2.7 .2’). The study of the distribution of frequency and damping has proven F.6 Lightning Location Systems useful with the identification of typical oscillatory modes crossing the different parts of the electrical network and As stated in ‘Annex 2b.v’, NPT considers the weak perfor- have aided in the investigation of the effects of possible mance of exposed 220 kV lines during lightning storms different damping values. as one of their most serious problems as this has been responsible for several supply disruptions in the Viet- Finally, this experience of monitoring oscillatory modes, namese transmission network. Installing surge arresters especially inter-area, will be very useful for future inter- on transmission lines in areas with a high incidence of connections with neighboring countries. In a large inter- thunderstorms is one possible remedy to minimize the connected network, inter-area oscillations are frequent impact of lightning on grid resilience and reliability. and it is important to be prepared to identify and adopt countermeasures against this type of system behavior. F.6.1 Transmission Lines Surge Arresters F.5.5 NPT project evolution NPT is currently considering the installation of these devices and the first transmission line involved in the In terms of the characteristics and capabilities of a WAMS project is the 220kV Tuyen Quang–Bac Kan–Thai Nguyen. project development as described above, it is useful to sum up some considerations and define possible imple- There are different options to equip lines with these mentation paths for a WAMS initiative in Vietnam. components, amongst which is either the installation of surge arresters on the entire route or only on those tow- The first step is a review of PMU positioning strategy, ers known to have already been struck by lightning or on including the possibility of installing PMUs on the 220kV towers located in high mountains. The costs for implement- network, in order to improve the real-time system observ- ing these various solutions are obviously very different. ability. As stated before, this phase will involve not only the operation and planning functions but also the asset This current project cannot be considered a Smart Grid management function whose contribution is crucial to project, given that the arresters are conventional com- achieve an effective PMU installation process. ponents and their installation is a traditional, well under- stood and mature remedy. PMU positioning strategy is significantly influenced by the type of applications to be developed for the WAMS On the contrary, given that storms often create signifi- system, so an identification of a list of desirable functions cant problems for the transmission network, especially to be implemented is strongly recommended. The NASPI in specific regions, the adoption of a Lightning Location roadmap, described in D.4.1, is an excellent example of System (LLS) able to collect real-time data and precise an appropriate approach with clear indications of priority, statistics about frequency and the hazardous nature of deployment challenges and time to complete for each lightning strikes should be considered as one of the key application. applications in the Smart Grid roadmap. 80 Smart Grid to Enhance Power Transmission in Vietnam Such an initiative has not been considered by NPT in its The basic phases are: roadmap, but the development of LLS is an opportunity for achieving significant benefits for the transmission a. The evaluation of all the available technologies system in Vietnam. This system improves overhead-line with respect to the specific needs of all the trans- engineering and design from the outset and streamlines mission utility functions that could benefit from network operations and the activities of field crews. such a system. b. The evaluation of the number of sensors needed With the help of an effective LLS application the instal- to cover the country with homogeneous and high lation of surge arresters can be achieved on the basis of detection performance, event discrimination, smart design management, engineering, operation and location accuracy and 24/7 availability. maintenance processes. c. The evaluation of the orography and consequently The following section describes the guidelines for devel- the identification of the possible ideal locations oping a LLS and highlights the benefits of the data for the sensors (electromagnetic noise, structural acquired by such systems. shields, physical security, terrain, telecommuni- cation, etc.). F.6.2 Lightning Location using simulation d. Appropriate contractual agreements with local algorithm site owners wherever necessary. Firstly, it is worth noting that it is possible to use simula- e. The execution of all civil and electrical works at tion algorithms to emulate the location of LLS devices the identified sites, including power and telecom- however this technique has quite limited abilities. munication cabling if needed. f. The implementation of an Operational Center There are complex tools that support detailed simula- provided with specific power and telecommuni- tions of electrical line behavior in the vicinity of a light- cation schematics and containing the main server ning strike. The overvoltage propagating along the line for data analysis where all sensor data will be and the effect of surge arresters positioned at different received, processed and stored. points can be studied, to analyze the effects of the entire lightning spectrum and, thus provide evidence of the g. The fine tuning of LLS (using the most immedi- best choices for surge arrester positioning. ately available data), implementing site correc- tions of detection parameters and thresholds However, in order to quantify the amount of potential where needed. damage, it is necessary to know the mean lightning den- h. The assignment of dedicated and properly trained sity at ground per year over the region traversed by the staff. electricity line being considered. To get the best out of simulation algorithms lightning trend information needs F.6.4 Benefits of Lightning Location System to be very precise but as the Vietnamese system has not data had the facility to capture such information about past lightning events available simulation tools for lightning Earlier sections have highlighted how the development location cannot be considered a viable strategy. of LLS can drive the planning phase for installing surge arresters. Here, it is worth underlining that not only Whilst the installation of LLS requires a significant invest- Grid Planning and Asset Management, but also System ment, it will provide maximum precision and accuracy in Operation (all of which functions are the responsibility of collecting data regarding lightning events, as detailed in NLDC in Vietnam) would benefit considerably from LLS paragraph ‘D.2.8’. technology. The data acquired by LLS provides estimations for each F.6.3 Guidelines for Lightning Location lightning strike, in terms of both the location and return- System development in Vietnam strike current amplitude. This information can be very To implement a LLS, a dedicated planning phase is useful for System Operation to understand whether needed, but such an activity is outside the scope of this lightning is the real cause of relay operation during thun- document. However it is useful to provide a short list of derstorms or not. Therefore, the data coming from LLS the basic actions required to deploy a LLS across the is usually integrated with data obtained from monitoring entire country. systems that record protection actions. Volume 1: Technical Analysis 81 In particular, the studies presented in the literature ([19], b. Power flow control; [20]) aim to understand the correlation between a light- c. Transient stability improvement; ning event and relay operation by means of establishing a time window and spatial distance criteria. Lightning is d. Power oscillation damping; and assumed to be the cause of a line fault if the two events e. Voltage stability and control. (lightning and relay operation) are recorded within a time window of a few seconds and the distance between the Some technical details about the FACTS technology are estimated strike location and the line is lower than a cho- shown in ‘Annex 3’. sen spatial threshold. In this way for each fault it can be determined if it is due to lightning or not, showing even- The table shown in Figure 49 displays the issues and tual critical behavior for specific areas or line branches. network problems that can be efficiently resolved by the installation of the most common FACTS devices within Moreover, LLS is also extremely useful in fast tracking the network grid and summarizes the main characteris- thunderstorms, thus providing a forecast of where a tics of each type of application. thunderstorm will strike and providing a means of antici- pating it by choosing alternative dispatching routes or by Looking at the problems and challenges of the Vietnam- alerting relevant field teams. This will certainly help in ese transmission network, the main concerns are related reducing the time to repair and generally bringing about to both power transmission capacity/controllability and power quality improvement. voltage profile control and stability. In principle, FACTS Further, it is worth underlining that, thanks to the storage of historical data on lightning events (with the availability of an adequate time window), it is also possible to calcu- FIGURE 49: FACTS MAIN DATA AND CAPABILITIES late the mean flash density at ground level for each area of a country. Recently a specific IEC Standard has ratified the LLS as a suitable and reliable application to calculate this value. This parameter could cover every square kilometer of Vietnam and, consequently, the most lightning prone areas could be avoided when installing a new line. Using this parameter for each kilometer of a power line the number of lightning events per year can be defined and expressed as a mean, thus giving an indicator for lines or branches that are more or less exposed. This information, together with the characterization of the lightning-fault behavior of each branch described pre- viously can be a clear indicator of the best location to install lines or to tune specific protections. F.7 Static Var Compensators A SVC is a power quality device, belonging to the fam- ily of FACTS systems, which employs power electronics to improve the voltage profile by continuously regulating the injected or absorbed reactive power. FACTS devices, thanks to their speed and flexibility, are able to provide the transmission system with several advantages such as: Source: Technical University Dortmund, 2010, (19) a. Transmission capacity enhancement; 82 Smart Grid to Enhance Power Transmission in Vietnam devices in either series or shunt configurations can be Two other SVCs with a regulation range of +/- 130 Mvar used successfully to address both problems. have been approved and will be installed on the tertiary winding of the 500/220 kV step down transformers in In practice however, it is necessary to note that in the two stations of the 500 kV North-South transmission sys- 500 kV systems, which are the backbone of the Vietnam- tem, located in the central and southern area, namely ese network, the 500 kV lines are already equipped with DaNang and O’Mon. fixed compensation (SC). They are intended to provide dynamic support of the volt- Furthermore the line sections are relatively short with age, optimizing the exchange of reactive power along the distances in the central area ranging between 259 to backbone link. 327 km, as there are many intermediate 500/220 kV sub- stations. So, based on an initial assessment, the appli- The proper setting and control of SVCs, including specific cation of FACTS series compensation systems does not stabilizing loops, could prove effective in stabilizing the seem very attractive. In any case, only a detailed network network, increasing the transmission capacity, optimiz- system study can confirm this initial indication. ing the voltage profile and consequently also reducing the losses along the lines without changing the topology On the other hand, the application of shunt type devices of the electrical system. For that reason they are defi- can be considered appropriate for addressing the prob- nitely considered part of a Smart Grid. lems with control of reactive power and in turn ensure control of the voltage profiles. In this regard, a very interesting example of the use of a SVC system within a typical smart application is shown in As described in ‘Annex 3’, the role of an SVC system is Figure 50, where a specific installation of an SVC system to adjust the amount of reactive power compensation is shown within the Nordic European grid system. to the actual system needs and then to control voltage which also has a very positive impact on dampening power oscillations, thus also increasing the transmission capac- FIGURE 50: EXAMPLE OF WIDE-AREA POWER OSCILLATION DAMPER ity. In fact, the very first examples of IMPLEMENTED WITH A SVC the installations described in Annex 3, such as the first application in USA for the EPRI-Minnesota Power & Light proj- ect commissioned in 1978, have already achieved significant and clearly identi- fied benefits with SVCs enabling a 25% power increase on lines where they were installed. Therefore, in the following sections the features and possible applications of SVC systems are analyzed in more detail and with reference to specific character- istics of the Vietnamese network. SVC systems are already in use on the Vietnamese grid in order to counteract the problems related to the voltage pro- file fluctuation. Two SVCs have already been installed, the first one on the 110 kV bus bar of the 220 kV Viet Tri S/S (+-50 MVAr) and the second one on the 22 kV side of the 220kV-250 MVA transformer of the 220 Source: IEA, 2013, (20) kV Thai Nguyen S/S (+/-50MVAr). Volume 1: Technical Analysis 83 In this case, A Wide-Area Power Oscillation Damper was In comparison with conventional large SVCs, a re-locat- implemented controlling a 180 Mvar TCR Static Var Com- able SVC provides additional performance benefits: pensator (SVC) installed in the Hasle substation of the Norwegian 420 kV transmission grid. a. Easy and quick relocation in response to network design changes. The SVC uses voltage phase angle signals from two b. By making a SVC re-locatable, dynamic voltage distant locations in the Norwegian grid as inputs to the support can be delivered where it is most needed damping controller. The damping controller modulates in the power grid to address current demands for the voltage reference set point used by the SVCs voltage network stability. Then, when the system con- controller, thereby creating a damping effect. figuration changes in response to the demands of a changing power market, the SVC can be relo- The Wide-Area Power Oscillation Damper is an extension cated to enable the system to adapt to the new to the existing Power Oscillation Damping (POD) control- situation. ler that uses local measurements and suitable switch- over logic to allow for the choice of no damping control, c. Moreover, considering that a re-locatable SVC local damping control or wide-area damping control. allows for the unit to be moved from one place in the grid to another on an ad hoc basis, SVCs can In this way, the issue of low frequency inter-area power be considered as a temporary solution to improve oscillations is resolved very effectively through the use network performance until other long-term rein- of special controls on the FACTS device and works as a forcement measures can be implemented. suitable control strategy on the power system stabilizers d. In this way, a re-locatable SVC can be considered loop. as an element which could both facilitate and make less critical the definition of the required However, like other FACTS devices, the SVC is an expen- phases for the development and implementa- sive system. Therefore it is important to define the imple- tion of the new substations and new lines which mentation strategy correctly and to integrate it with the necessarily involves much longer time scales to operation of the traditional system components and the accommodate the design, location selection, normal practices for voltage regulation. installation and commissioning phases. In particular, it is very important to find the optimal loca- The unbundling practices applied to the electricity market tion and the correct capacity of the SVC in a power sys- that produce a transition from a centralized system to a tem so that voltage profiles may be effectively improved more deregulated environment, tend to increase the dif- thus optimizing the investment. ficulties for the system operator and planners to forecast future development and expansion of the transmission The proper location and sizing of SVC systems must be network by more than a few years ahead. based on a detailed system study and design analysis of the network. The installation of a new generating plant or new high voltage connections may greatly strengthen weak points In particular the assessment of the benefits that can be and render an SVC installed in a specific area practically achieved thanks to the installation of the SVC systems redundant after only a few years of service, whereas requires the execution of appropriate system studies. other developments may result in the closure of some In principle, the fast system response of the regulation generating plants or in an unexpected change in load pro- provided by the SVC can reduce the risk of outages that files, with consequent weakening of the network in that could affect large areas of the network, with a significant specific area. impact on the levels of reliability achieved, which leads consequently to a substantial reduction in the System The result is that a SVC installed as fixed substation plant, Average Interruption Duration and System Average Inter- to meet a medium- to long-term need with a typical antic- ruption Frequency Indices. ipated lifetime of 25-30 years or more may then not be connected to the right node at the right time to provide Re-locatable systems may be considered for this issue, the required voltage support for the network. This is the given the rapid development and possible reconfigura- more obvious disadvantage of a fixed SVC system in the tion of the Vietnamese grid, which will immediately transmission grid, especially in cases where the network change the requirements and shift the location of critical is in a state of flux, as in Vietnam. nodes of the system. 84 Smart Grid to Enhance Power Transmission in Vietnam This is the reason why various TSO have specified re- related to the electric design of the system, which must locatable SVCs as the preferred solution. be aligned with the requirements to allow the installation of the system in different areas of the network as well In order to get a re-locatable configuration, the SVC as factoring in different operating conditions and a wide installations need to be compact and avoid any perma- range of system parameters. nent fixed structures. The technical solution normally includes the use of sections Outdoor equipment (reactors, capacitors, etc.) are nor- of compensation (typically TSC) with binary multiple power mally arranged in-groups of components, mounted on steps (see example of Figure 51: 102040 Mvar steps, with skids or special frameworks, which can be easily carried, corresponding operating points). In this way the rating, tun- by road or rail, with just the minimum site activity for ing and implementation of the system can be easily modu- mounting or dismantling. lated to meet the needs of the new installation site. Other more sensitive components of the SVC, such as It is worth noting that the development of the STATCOM the thyristor valves, Protection & Control modules, aux- system lends itself to this level and type of modularity iliaries, etc. are installed within transportable cabins to and is easily relocatable. provide weatherproof housing. In this case the compensation modules are not only TSC Whenever possible, the most convenient solution is to systems but also STATCOM voltage source converters, connect the SVC system to the tertiary winding of the which can continuously modulate the exchange of reac- substation transformers. In this way it is not necessary to tive power with the network. This solution is simpler but provide for the installation of a dedicated SVC transformer. inevitably more expensive. On the other hand this solution implies a limitation on The previous section ‘D.3.2’ provided a detailed analysis the size of the SVC system according to the standard- relevant to the application of SVC systems in the UK and ized rating of the transformer and can lead to the need to includes an extensive description of the use of re-locat- provide a larger number of SVCs, with reduced ratings, able systems. distributed across multiple transformers. The concept of re-locatable SVCs has either been imple- The major effort required for the definition of the char- mented or merely studied in other countries, where the acteristics of a re-locatable SVC system, however, is need to provide voltage support must be accommodated FIGURE 51: SYSTEM CONFIGURATION AND OPERATING POINTS FOR A RE-LOCATABLE SVC Source: SIEMENS, 2013, (17) Volume 1: Technical Analysis 85 in the context of a fast growing, dynamic and rapid devel- HVAC and power flow controllability, which can opment of the transmission system, such as in South enhance the stability of the link and of the surrounding Africa and Algeria [21]. electrical system and thus increase the transmission capacity of conventional AC systems interconnected by the HVDC link. F.8 High Voltage Direct Current technology The accurate control of the active power in the HVDC link can ensure significant stability improvements for the link High Voltage Direct Current (HVDC) technology has itself and for the surrounding AC system. In fact, unlike proven its reliability and is an effective option for specific conventional HVAC transmission, the active power flow- applications such as long distance bulk power transmis- ing through an HVDC link is not determined by the link sion, long submarine cable links and interconnection of impedance in relation to the impedances of the neigh- asynchronous systems. boring transmission lines, but only by the settings of the HVDC converter control. Countries like Brazil use this technology to carry the large generation from Itaipú (one of the largest hydro power The HVDC transmission link can operate at a fixed work- plants in the world) and also for interconnecting their north ing point, which can be maintained or rapidly regulated and northeast areas with the south-southeast areas. during disturbances on neighboring transmission lines and AC grid sections. Two different technologies are available today, viz. thyris- tor converters, also called Line Commutated Converter This characteristic prevents the HVDC link from over- (LCC), see Figure 52, which shows examples of systems loading when a neighboring transmission line is lost and that have been in service since the 50s, and transistor assures a consistent transmission capacity in terms of converters, also called self-commutated Voltage Source the line rating. Converter (VSC), see Figure 53, developed in the late 90s [22]. The peculiarities of each HVDC technology are sum- The consistent transmission capacity of the HVDC link marized in Figure 54. is assured without any limitation caused by network congestion or loop flows on parallel paths as well. Link The key benefits of HVDC are in terms of both increased capacity with HVDC is generally higher than that of extra transmission capacity, compared with conventional high voltage AC transmission and also lowers the trans- mission cost per MWh. FIGURE 52: LCC HVDC CONVERTER CONFIGURATION Source: ABB, 2013, (8) 86 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 53: VSC HVDC CONVERTER CONFIGURATION Source: ABB, 2013, (8) FIGURE 54: HVDC MAIN DATA AND CAPABILITIES Source: Technical University Dortmund, 2010, (19) Volume 1: Technical Analysis 87 Moreover the HVDC power flow controllability is also Studies performed on typical configurations, with AC very beneficial for the parallel AC transmission as it frees and DC parallel corridors, shows significant increase in up transmission capacity on neighboring AC lines. the transmission along the AC lines, with final utilization close to the thermal limits of the system, see example This positive effect on neighboring AC network paths has shown in Figure 55. to be taken into account during power flow analyses in order to perform a complete cost benefit assessment of The most recent technology, the VSC converter, is even the HVDC system impact on the transmission system. more flexible than the conventional line-commutated converter, since it allows a faster and more independent control of both active and reactive power, as shown in Figure 56. FIGURE 55: TRANSMISSION CAPACITY IMPROVEMENT In this way, the converter can contribute to the regulation of the AC system voltage like a generator during emergency situa- tions and can operate at a fixed value of transmitted power even in the presence of fault conditions in neighboring lines. These specific features help to improve the over- all stability of the surrounding AC power systems. Furthermore, since HVDC VSC can contribute to power oscillations damp- ing, it also enhances network stability dur- ing emergency situations. Since the VSC converter does not require the presence of an active AC supply (as Source: IEA, 2013, (20) opposed to the LCC converter, where the FIGURE 56: LCC AND VSC REACTIVE POWER CAPABILITY Source: IEA, 2013, (20) 88 Smart Grid to Enhance Power Transmission in Vietnam availability of a sufficient level of short-circuit power com- Other positive aspects that can be associated with the pared to the rated power of the converter is required), use of a HVDC system are in general: black start capabilities can also be ensured by VSC- HVDC, to allow the fast re-energizing of an AC network a. A very high level of reliability and availability. This following a system blackout. is not because of highly stringent component requirements in VSC systems but is rather a A broad range of application control functions can be function of the modular design of the converter implemented in a VSC-HVDC system for enhancement of bridge, which is inherently fault tolerant. the steady-state and dynamic performance of an AC net- b. A level of resulting transmission losses (convert- work. These control functions are shown in Figure 57 split ers + OHTL or cables) over significant distances into three categories along the time line for a disturbance: is lower than those present in an equivalent AC system. a. Pre-disturbance phase; c. In particular, the development of multilevel VSC b. Transient phase; and converters has also reduced the losses for the c. Post-disturbance phase. FIGURE 57: VSC CONTROL FUNCTIONS VS. DISTURBANCE TIME LINE Source: ABB, 2013, (8) VSC converter to levels that are comparable with FIGURE 58: VSC LOSSES OPTIMIZATION TREND the LCC, see Figure 58, showing the reduction trend in VSC converter losses [23]. d. The choice of HVDC instead of HVAC transmis- sion has a reduced environmental impact as, for the OHTL, the right-of-way can be reduced by approximately 30-50%. The electromagnetic emission of HVDC lines does not pulsate and can be forced to minimum values to ensure signifi- cantly lower electromagnetic pollution compared to the emissions of conventional HVAC transmis- sion and this includes the related effects in term of audible noise and possible radio frequency interference with other systems. Source: ABB, 2013, (8) Although the investment costs of a LCC or VSC HVDC converter station are higher than for a conventional AC Volume 1: Technical Analysis 89 substation, the overall investment costs of a DC trans- b. Enable new business opportunities and market mission link can be lower than for a corresponding AC models; interconnection given a minimum transmission distance c. Allow more coordinated planning and integrated (i.e. “break-even” distance). operation of the grid given the expansion of most networks caused by a growing number of inter- This break-even distance is highly contingent upon the national connections; and specific project parameters and can be affected by vari- ous constraints and specific needs of the network under d. Support and facilitate the introduction of new mar- consideration. ket rules at both national and international level. In addition to the classic HVDC applications described Given the capabilities assured by the HVDC systems and above which take advantage of their specific characteris- their impact on the operation of the AC transmission grid tics and in particular of their inherent controllability sev- this technology could be also be considered as part of a eral TSOs and manufacturers are considering their future Smart Grid initiative. See the example of increased stabil- use on production networks. There are already several ity of combined AC and DC system shown in Figure 59. examples of real world applications already implemented or in an advanced stage of installation and that may The analysis of solutions that could integrate one or more establish a new paradigm for emerging grid architectures HVDC links in the AC grid implies the verification of all based on a combination of HVDC and conventional HVAC key parameters that optimize the operation of the net- solutions in conjunction with the use other active control work, as already pointed out, in terms of the expected equipment to deliver a more efficient and reliable grid impact on: system [24]. a. The reliability of the transmission system; An AC and HVDC combined grid will be better able to b. Power system controllability; accommodate and respond to new requirements result- ing from a rapid evolution of the electricity markets such c. Increased transmission capacity; as the need to: d. Minimizing transmission losses; and a. Actively integrate new types of power generation e. The definition of integrated solutions with and consumption models; reduced environmental impact. FIGURE 59: TRANSIENT STABILITY ENHANCEMENT WITH HVDC PARALLEL LINK Source: Friends Of the SuperGrid, 2012, (21) 90 Smart Grid to Enhance Power Transmission in Vietnam Based on the above comments, the possible integration region has a target in terms of total import capac- of HVDC interconnections within the AC network can ity of about 2,000–3,000 MW for 2030. Some of also be considered for the Vietnamese network over a these connections in terms of power levels and long-term time scale given: length of the line, fall within the range of applica- tions that could benefit from HVDC technology. a. The high rate of growth of the grid expected for the near future, which may lead to congestion With regard to the development of interconnections with problems and bottlenecks in the main load area other TSOs, the option of using a HVDC system allows of the grid with the need to control the levels of the definition of a solution in which the operation of the short circuit current and avoid loop-flows; these interconnected AC systems is substantially decoupled. issues are discussed in more detail in the fol- lowing section. Considering, however, the rate In this case the technical standards applied by each TSO of development of the network and new instal- do not need to be altered which is helpful as they can lations planned in terms of 500 and 220 kV lines vary significantly between countries. and new substations, as per the following table of Figure 60 derived from master plan VII, this type This applies for example to: of problem could actually arise in various areas of the country, as evidenced by international experi- a. Characteristic types and ratings of network ences in other countries. components; b. The possible development of generation from b. Operating modalities; renewable sources that could be located at some c. Fault responses; distance from load centers. In fact master plan VII, prioritizes the development of renewable d. Setting and calibration of the control systems; and energy sources for electricity production, increas- e. Specification of protection and control apparatus. ing the percentage of electricity produced from these energy sources from 3.5% of total electric- A solution based on a HVDC link would allow for easier ity production in 2010 up to 4.5% in 2020 with a negotiation of potential operating conditions and exploi- target of 6.0% for 2030. Also in this case, inter- tation of future interconnection between the TSOs national experiences concerning the presence of involved. a strong component of RES generation, in par- ticular if located in peripheral areas of the coun- This favorable situation is achieved by eliminating all the try, has shown the tendency of dedicated HVDC potential technical limitations and constraints that could links to achieve better management of these make the project less attractive or even inconvenient or sources. HVDC technology allows for easier inter- impractical for the participating agencies thus allowing connection of RES generation with a substantial them to focus exclusively on the definition of the most decoupling with respect to all those disturbances favorable economic conditions for the exploitation and that are associated with this intermittent type of utilization of the proposed new infrastructure. generation. Again, these issues are discussed in detail later on. Considering the potential long-term prospects for the c. Vietnam’s policy regarding international intercon- use of HVDC systems in the Vietnamese network, it is nections to power grids of other countries in the appropriate to define and identify some key elements FIGURE 60: PLANNED DEVELOPMENT OF 500/220 KV EVN/NPT GRID Source: NPT-World Bank, 2013, (18) Volume 1: Technical Analysis 91 concerning the development of the related technology in HVDC systems of the LCC type. The trend for VSC con- an attempt to identify possible development trends and verter systems instead is shown in Figure 62. implications of specific applications in the future. The comparison between the two figures shows that the The following Figure 61 shows the growth trend for LCC systems are increasingly used for bulk power trans- the transmitted power and the voltage level applied for mission over very long distances, whereas VSC systems FIGURE 61: DEVELOPMENT TREND OF LCC CONVERTER TECHNOLOGY Source: ABB, 2013, (8) FIGURE 62: DEVELOPMENT TREND OF VSC CONVERTER TECHNOLOGY Source: IEA, 2013, (20) 92 Smart Grid to Enhance Power Transmission in Vietnam are being used in an expanding range of applications for such as Caprivi, in Africa (350 kV/950 km, 300 MW transmission over medium distances with increasingly monopole) but with additional future proofing by includ- higher power levels in particular within AC integrated ing additional converter and bipolar operation/expansion systems, as clearly shown in Figure 63. to 600 MW. Based on the actual trends and development scenarios However, considering the technology available today, predicted for the electrical system in Vietnam and in a DC 500 kV link circuit could provide a transmission particular the potential development of new intercon- capacity similar to that of a dual circuit 500 kV AC line at nections with neighboring countries (Laos, Cambodia), it about half the cost [25], see Figure 64, making the HVDC is likely that the most appropriate option to integrate a solution economically viable for distances less than 600 HVDC system within the current or future AC network, km (but the break-even distance is heavily dependent on would be based on VSC technology. The gradual adop- the costs for line construction civil works) with power tion of this technology particularly across the EU and the delivery capability of up to 2,000 MW [26]. USA will deliver improvements, enhancements and inter- national standards as well as decreasing costs making it HVDC technology will serve the needs of the Vietnam- ever more attractive and affordable for the Vietnamese ese electrical network very well in the light of the targets to consider as a future enhancement, since the applica- defined in the national master plan for power develop- tion of the traditional LCC technology seems increas- ment over the 2011–2020 period, such as developing ingly intended for applications with power, voltage levels a balanced capacity of power sources in the Northern, and distances above the levels of interconnectedness Central and Southern regions, ensuring the reliability of expected for Laos and Cambodia. However, in the case power supply systems in each region in order to reduce of development of bulk import from China this type of transmission losses, sharing capacity reserves and effi- more traditional technology may still be considered. ciently exploiting hydro power plants in all seasons. The implementation of a HVDC system could deliver signifi- The application of HVDC technology for the Vietnamese cant benefits to the Vietnamese transmission grid given network can be seen as a possible solution for dedicated the predominant north-south alignment of its topology interconnections to the networks of neighboring coun- particularly in terms of the 500 kV backbone configura- tries based on the experiences of international projects tion but primarily for the significant polarization of load FIGURE 63: APPLICATION AREAS FOR LVV AND VSC CONVERTERS Source: IEA, 2013, (20) Volume 1: Technical Analysis 93 FIGURE 64: TYPICAL RELATIVE COSTS FOR DC AND AC OHTL’S Source: Alberta Energy, 2009, (22) and generation in the two extremities since SPC and c. A significant increase in the reliability of the sys- NPC are not only the regions with the highest share in tem thanks to the lower levels of the RAM asso- power consumption but also the ones with the highest ciated with a HVDC system in comparison to the growth rate. various problems related to operating a complex system of AC lines and stations with their aux- A HVDC system would deliver a substantial reinforce- iliary systems, protection and control apparatus, ment of the global conditions of north-south load flow for etc.; a relatively limited investment. d. A substantial reduction of the load on existing 500 kV AC lines; and This option could be technically and economically benefi- cial. In fact, a north-south point-to-point DC transmission e. No impact on the levels of short circuit on exist- link could provide: ing stations. a. A cost-efficient configuration where the overall In the long-term perspective another potential use of cost of the DC system would be less than the HVDC systems could be to supply large urban areas. global investment need for the reinforcement of the AC system such as additional lines or modifi- The majority of large city power grids are characterized cations of the existing stations/new substations; by high load densities, stringent and ever increasing requirements for reliability, power quality and significant b. A transmission of bulk power between the two reliance on power imported from outside sources. main areas achieved with a substantial reduction of transmission losses; 94 Smart Grid to Enhance Power Transmission in Vietnam Increasing the power delivery to such large urban areas c. Significant increase in the utilization of AC lines relying solely on the AC expansion option is often limited belonging to the same nodes; by various critical issues: d. Reduction of congestion on parallel AC lines; and a. The risk of increasing short circuit current beyond e. No increase in short circuit levels. critical levels; In the previous section ‘D.4.4’, some details on one of b. The possibility of generating widespread distur- the above mentioned applications, namely the Trans Bay bances; and Project example, USA was provided where both the tech- c. The identification of transfer capability limitations nical and economic benefits i.e. reduction of losses and and AC network expansion restrictions. economic dispatching were also summarized. There are various examples available today where an unconventional solution based on direct DC feed-in has F.9 Fault Locator System been implemented. One of planned initiatives in the NPT Smart Grid roadmap Currently a point-to-point HVDC system delivers power is the development of a Fault Locator System (FLS). This directly to inner city load centers (e.g. Cross Sound/330 project is already underway and six of the most important MW, Neptune/660 MW, Trans Bay/400 MW in New York substations of the 500 kV transmission network will be and San Francisco areas, USA). equipped with FLS devices during 2015. Other fault locators will be installed in key substations of the 220 kV network. Again, it should be noted that the contribution provided by the HVDC link has multiple effects for this specific Figure 65 depicts the basic components involved in such application: a system. It can be seen that the data produced by FLS devices will be transmitted to NLDC and NPT remote a. Consistent transmission of power to the thermal centers for processing and operation. limit of the link; b. Significant stability of the system; FIGURE 65: VIETNAMESE FLS PROJECT Source: NPT-World Bank, 2013, (18) Volume 1: Technical Analysis 95 This project can be seen as a Smart Grid solution to basic interventions suggested earlier for improvements reduce time and cost of asset maintenance, which has of the Asset Management and Planning strategies (see been described as one of the challenges of the Vietnam- paragraph ‘E.3.1’) are necessary and probably more ese transmission system (see ‘Annex 2b.x’). urgent than FLS implementation. In particular, NPT considers its main project objectives as: F.10 Power quality monitoring system a. The reduction of line patrol manpower costs; b. The prevention of re-occurring faults; In ‘Annex 2b.xi’ the improvement of power quality levels is introduced as a challenge for the Vietnamese network. c. The reduction of the impact on power quality of In order to achieve this end the development of a power “preventable faults”; quality monitoring system is an appropriate Smart Grid d. The reduction of costs to maintain system secu- application. rity during line outage; and Towards this aim it is fundamental to carry out a device e. The reduction of regulatory fines for power installation activity to cover the most significant points outages. of the transmission network and then to enable the This system bases fault location on travelling waves for necessary TLC system to collect their data in a central overhead lines and the fault locating devices can find the repository. In this way it will be possible to perform mea- fault using the transients generated by the fault itself or surements to define the expected levels of voltage qual- by using the transients generated by the re-closure of ity and define practical PQ standards that will apply to the circuit breaker onto the faulty line after the initial trip. all the agencies connected to the transmission network. Using the travelling waves principle the location algo- Furthermore, thanks to a unique storage system for PQ rithms of these components, which differ from conven- data it is possible to investigate the real causes of poor tional fault locators based on fault impedance are not PQ events in a manner that can accurately establish affected by fault resistance and so their accuracy level is whether they originate from the transmission network, usually higher. In particular, such accuracy levels are guar- the distribution network or the user’s installations. Thus, anteed by the simultaneous use of the transmission line further information will be available to all stakeholders of equations and GPS synchronization. Its precision makes the Electricity market (such as, customers, regulators, this system extremely useful on long lines. etc.) who have an interest in updating the standards and/ or in drafting new agreements regarding PQ key perfor- This system is useful for locating different types of faults mance indicators (“Quality contracts”). (phase-to-ground, phase-to-phase, etc.) and the col- lection of all data acquired by a remote center can be A central management system will allow control center processed using different techniques. These include the applications to match, compare and post-process all data simple double-end methods that do not use data from coming from the smart appliances (network automation neighboring substations these algorithms fail if one of and remote control, metering, demand management the data acquisition devices at either end of a line does systems, PQ monitoring, etc.) integrated in the SCADA not succeed in capturing the fault transient. To avoid this network. Such analysis will improve the understanding it is possible to implement wide-area travelling wave fault of the actual level of voltage supply characteristics pro- location algorithms, which make use of travelling wave viding more data and information about the causes and data from various substations across the monitored propagation of PQ disturbances. For this purpose a large network. number of measurement points will provide enough data for accurate and relevant statistical analysis leading The level of precision achievable in fault location by such to meaningful results as the basis for developing new systems can lead to significant improvements in asset functionalities. maintenance activities and to meet NPT’s key perfor- mance indicators. Figure 66 shows an example of correlations between voltage dips and commensurate network events. The The FLS features make this system a very useful and blue spots are the voltage dips which correlate with iden- advanced solution that could benefit the Vietnamese net- tified network events. work. However, it is important to consider that all the 96 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 66: CORRELATION DIAGRAM BETWEEN VOLTAGE DIPS AND THE NETWORK EVENTS Source: Authors Therefore, PQ analysis provides more data and infor- F.11 On-line Dissolved Gas-in-oil mation about the causes and the propagation of the Analysis for Power Transformers disturbances which could help to optimize investments in installations to increase resilience to voltage dips or Reliable energy flow is paramount and power transform- other potentially harmful voltage characteristics. ers whilst critical to ensuring this reliability are quite costly assets in a transmission grid. As an asset type, Finally, international experiences investigated in ‘D.2.9’, power transformers constitute one of the largest invest- may provide a helpful best practice for the use of PQ data ments in a utility’s system. For this reason transformer analysis for the assessment of protection systems per- condition assessment and management is a high priority. formance. As stated in ‘Annex 2b.viii’, miscoordination of the protection systems are one of the main issues high- In several parts of the world the transformer fleet is oper- lighted in the Vietnamese transmission network. Towards ating beyond its design life and with higher average loads this end the number of voltage dips and commensurate than ever before. Some statistics on the North American protection behavior, as seen in Figure 17 , could be corre- power transformer fleet follow: lated to identify whether an anomalous number of events correspond to the 2nd step of the distance protections, a. The average age of power transformers is in thus revealing the presence of incorrect settings or mal- excess of 42 years and increasing by 0.6 years functioning processes. per year; and The information about events acquired by PQ monitoring, b. Transformer failure rates, both catastrophic and together with its integration in the other systems just non-catastrophic, continue to increase. described, can help pinpoint problems and track down their causes. The cost of replacing enough power transformers to reduce or flatten the growth of the average age is not a Volume 1: Technical Analysis 97 cost-efficient alternative for most electrical utilities. This The example demonstrates why on-line DGA has become situation demands the best asset management and con- increasingly relevant for timely fault detection, especially dition assessment approaches available to optimize the in the context of the ageing worldwide transformer fleet. sunk investment in the existing fleet while maintaining reliability to ever higher standards. In particular, on-line DGA has enabled the monitoring activity to evolve from the collection of infrequent snap- Dissolved Gas Analysis (DGA) is recognized as a power- shots of transformer conditions in time to understanding ful monitoring technique for the detection of emerging the dynamic behavior of gases over the daily operating faults within transformer main tanks and associated oil cycles of the transformer delivering new and previously filled equipment. Extensive historical data collected by unavailable insights. laboratory analysis over the years is a useful basis for the accurate interpretation of results. DGA online monitoring systems are another component of the smart maintenance of the network and hence part The experience earned in data interpretation is crucial of a Smart Grid roadmap. This technology is a very effec- to fully exploit this monitoring technology. Figure 67 tive transformer fault prevention and Asset Management shows an example of the analysis of multiple gas trends. strategy. A Smart approach for managing the mainte- The trend graph clearly shows decreasing oxygen and nance process would collate data from a DGA system increasing carbon monoxide levels. The presence of car- with data collected from visual inspections, measure- bon dioxide indicates overheating of the paper insulation ments and operations. in the transformer. These trends usually lead to a rapid increase in hydrogen and acetylene indicating an elec- Even though this initiative is not present in NPT’s Smart trical fault. The anomalous trends of oxygen and carbon Grid roadmap they have already started a project install- can be observed about three months before a potentially ing on-line DGA sensors and they anticipate completion catastrophic fault event. for their most critical transformers by the end of 2015. The FIGURE 67: EXAMPLE OF DISSOLVED GAS TRENDS Source: General Electric, 2013, (23) 98 Smart Grid to Enhance Power Transmission in Vietnam full rollout of such an initiative can be assigned a medium/ of the conductors. In fact, traditional static line ratings long term time scale on their Smart Grid roadmap. were expressed as the Ampere limits calculated during the project phase and were based on average boundary A successful deployment of such technology will entail conditions (e.g. weather conditions) but nowadays they equipping transformers with DGA sensors but a different are usually based on the thermal limits of the conductors. approach will have to be taken with new transformers. DTCR is based on the calculation/estimation of the con- Whilst no particular analysis has to be performed before ductor temperature in real-time so that calculating the installing new transformers it is worth including DGA real Ampere limit of the line during existing weather con- devices in all of them. This is because the cost of these ditions is possible. Furthermore, knowing the present DGA components is negligible (about 2%-3%) com- temperature of the conductor is necessary not only to pared to the cost of the whole transformer. The return calculate the static Ampere limit of the line but also to on investment would be more than sufficient if even one estimate how much the line may be overloaded by a spe- of these monitoring systems per transformer prevented cific over-current prior to reaching the thermal limit of the an outage. conductor. This goes beyond the estimation of the aver- age current and of the thermal time constant of the line. On the other hand, the installation of on-line DGA device in old transformers requires a pre-requisite activ- DTCR takes into account the real thermal stresses on ity to identify the most critical and valuable ones to be lines and equipment by making dynamic characteriza- protected by this new technology. In most cases DGA tions of networks limits. A successful implementation of monitoring reveals its real added value when consistent DTCR optimizes use of the transmission lines which is historic data collection has been performed. Such devices why it is one of the most important applications within evaluate on the basis of variations of given parameters, the Smart Grid suite. as seen in the example shown in Figure 67 , and not on instantaneous values. NPT has quite rightly considered this initiative in its Smart Grid roadmap but it would probably be better to develop It is entirely possible that a transformer that has worked it in the medium/long-term and not in the near future. The quite reliably for a long period (15-20 years), once Vietnamese network is growing very rapidly and the loca- equipped with one of these devices reveals anomalous tion of the most overloaded lines changes almost daily values for some parameters. There are cases where this as a function of the installation of new power plants or reveals the existence of a real problem, as in the BC other lines. Thus, at the time of writing this report it is Hydro experience described in paragraph ‘D.4.3’. How- very difficult to identify a significant number of lines to ever, in other cases these outliers are false positives i.e. be monitored with DTCR. Instead, the development of those values, which in general can be considered abnor- a DTCR pilot project on a small group of lines (34) could mal for a specific transformer could be totally normal be a good basis for the future use of this application on and do not indicate any imminent fault, especially if such a large scale and when the rapid growth rate of the net- parameters remain stable. work slows down. Therefore, when old transformers are equipped with The possible steps for a pilot project are to initially test DGA sensors, it is essential to perform a careful analy- some different DTCR techniques on a small group of sis that combines the new monitoring features with lines in order to collect the results and highlight criticali- traditional techniques so as to avoid false positives and ties of these methods and then to use this information ensure a set of consistent data to characterize the typical to lead to the possible deployment of the technology on behavior of such transformers. a large scale in the medium/long-term. The NYPA experi- ence described in D.4.2.1 may be very helpful in terms of both the small size of the project and the use of different F.12 Dynamic Thermal Circuit Rating types of DLR devices and techniques. The real-time monitoring of the network is an important DTCR methods are based on the estimation of the line tool at the disposal of TSOs as it will aid the efficient and temperature in real-time and the subsequent calculation safe operation of the electrical system. Dynamic Ther- of the residual loading margin. There are two techniques mal Circuit Rating (DTCR) provides an estimation of the for estimating temperature and they are either by direct actual loading of the line and indicates by how much the measurement or by with algorithms that use electrical line may be overloaded before incurring premature aging quantities as input. Volume 1: Technical Analysis 99 Using the first type of technique calculates the tem- way of evaluating their performance is to analyze where perature estimation by using a thermal model of the line they have been successfully deployed around the world and based on knowledge of weather conditions. However, making a selection on the basis of those geographical loca- weather conditions may vary significantly along the line, tions with environmental conditions and line spans compa- especially for long connections, so that this method is not rable with Vietnamese conditions and line spans. always the most accurate. Another common approach is to equip the line conductors with devices that measure The next step will be the installation of PMUs at both the sag and temperature. However, this method is more ends of all monitored lines. The measurements they pro- suited to the estimation on a single critical span rather vide will make it possible to use an algorithm for real- than on an entire line. time reconstruction of the electrical parameters and consequently for the estimation of line temperature. To overcome the limitations of these methods algorithm based calculations using electrical quantities as inputs Finally a dedicated algorithm has to be implemented to can be implemented. On this subject a very interesting select the final temperature used for the estimation of example is the estimation based on WAMS measure- the time constant of the line. The final temperature will ments. This technique consists of the real-time recon- be identified by selecting one of the three or a combina- struction of the electrical parameters of the line based tion of them on the basis on the reliability of each method on extrapolation from the WAMS measurements. Com- which will vary according to data characteristics. paring the realtime values with standard values it is pos- sible to estimate the current temperature of the line with The final objective is to monitor a large number of electric sufficient accuracy to apply it as a mean value along the lines to estimate their overload limits in the best pos- whole length. sible way and to use these as an inputs of optimal power dispatching algorithms (i.e. OPF). In this way, where the WAMS is one of the Smart Grid initiatives considered calculated dynamic limits are higher than currently avail- earlier (F.5) but if the measurements derived from it are able static ones, it will be possible to relax some of the used as inputs for DTCR systems it is important to high- optimization procedure constraints and define a better light some concepts. Compared to other applications dispatching strategy, which leverages the actual line load that could be developed on a WAMS (such as oscillation margins. Figure 68 shows a possible path to develop a monitoring, voltage stability monitoring, etc.) the require- DTCR project. ments for the inputs of a DLR algorithm are more chal- lenging regarding the precision of the measurements (especially the voltage module) and PMU synchroniza- F.13 Geographic Information Systems tion. Moreover, the PMU installation plan must consider the lines that have been chosen for the DTCR project as In general terms a Geographic Information System (GIS) these lines must be equipped with PMUs at both ends. refers to any application that integrates, stores, edits, analyses, shares, and displays geographic information. The best approach is to design a DTCR project that uses GIS tools allow users to create interactive user-created all the different techniques proposed. To do this, the first queries on geographical data, link spatial information with step is to evaluate which lines are most in need of moni- external data sources (e.g. load consumption), edit data toring, selecting the ones that are usually characterized in maps and present the results of all these operations. by high current transits or overloading. Thus, GIS can be integrated with a number of different technologies and/or processes regarding operation, plan- Once the target lines have been selected, it is impor- ning, asset management, telecommunications as well as tant to know the structural characteristics of the single electricity markets. spans in order to build a thermal model, span by span. This model will uses estimates of weather conditions as In their roadmap NPT has considered this project as inte- inputs to predict the temperature of the lines. To ensure grated with the Information System for Asset and Out- the accuracy of this process it is very important to choose age Management. An example of the different levels, a suitable range of weather forecasts. layers and type of geographical representations being considered are depicted in Figure 69. The knowledge of the characteristics of individual line spans will be very useful to identify the most critical ones It is worth noting that GIS can embrace a wider scenario. and to equip them with devices dedicated to the direct Providing a synthesis which connects the events and measurement of sag and temperature. There are differ- measurements with their geographical location is par- ent types of devices available on the market and the best ticularly useful for a great number of applications. 100 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 68: POSSIBLE DEVELOPMENT OF A DYNAMIC THERMAL CIRCUIT RATING Source: Authors FIGURE 69: EXAMPLE OF DIFFERENT LEVELS OF GIS Source: NPT-World Bank, 2013, (18) Not only Asset Management but also System Operation such an initiative both NPT and NLDC could share geo- functions can benefit from GIS. Most of the initiatives, graphical information related to the electrical network especially Smart Grid ones, described earlier (like New and its devices. SCADA/EMS system, WAMS, Lightning Location Sys- tems, etc.) can be developed on the basis of including In order to do this, the first step is deciding those ini- geographical information as a key point. Therefore, in tiatives whose applications could be provided with GIS Volume 1: Technical Analysis 101 input and then provide and collect reliable geographical F.14 Metering Data Acquisition System information of all necessary network elements. It is also very important to choose a common data format and a Metering Data Acquisition System is a conventional and shared policy to archive, update and exchange the geo- mature system widely adopted by several power trans- graphical information. mission networks with a mature and functioning open market. A reliable and pervasive measurement system In this way the geographical information related to a is a key element and an enabling technology for the network element that may prove useful for the differ- achievement of an open energy market and for that rea- ent functions of a transmission utility, such as System son, if no other, it should be included in the roadmap for Operation and Asset Management, will be available to the Vietnamese Smart Grid. all authorized users. For example PMU and WAMS can be considered as likely candidates. The geographical rep- NPT has already planned such a project and its purpose resentation of PMU locations would be fundamental for is to provide an accurate, reliable and real-time measure- Asset Management to control their assets and to verify ment of energy consumption and supply at all network their correct operation. Equally for System Operation, the points where energy is purchased or sold. same information would be an essential input in a geo- graphical representation of WAMS. This system is mainly oriented towards market applica- tions aimed at supervising input volumes, net sales and GIS cannot be described as a single Smart Grid initia- losses. However, the data from the meters could also tive but needs to be seen as a possible enhancement be used for other applications such as load forecasting, for other applications. It is appropriate that both NPT and overload prediction, measurement checking and warning NDLC evaluate the possible added value of the availabil- of damaged equipment ity of geographical information for all the initiatives they plan to develop. This analysis will drive the implementa- Figure 70 shows a project overview and it can be seen tion of their functions and, over time, provide inputs for that, as for the Italian project described in paragraph new features. ‘D.2.10’, part of the data comes from substations. This FIGURE 70: METERING DATA ACQUISITION SYSTEM PROJECT OVERVIEW Source: NPT-World Bank, 2013, (18) 102 Smart Grid to Enhance Power Transmission in Vietnam system could benefit from the system improvement generation function. The requirement of measurability developments of the devices and telecommunications is the basic condition for the admission of each power for the SAS initiative (described in paragraph ‘F.4’). plant to the electrical market. There are two fundamental aspects: As for other Smart Grid solutions previously discussed, Metering Data Acquisition System requires the installa- a. The accuracy of the measurements available for tion of monitoring devices that acquire data and a tele- each power plant; and communication system to transmit that data to a central b. The identification of the agency responsible for information system. the collection, validation and recording of electri- cal data. This project has to deal with a number of technical issues. Due to the acquisition of the measurement problem Such considerations reveal the necessity to develop, at there is a significant amount of information to process, the beginning of the project, a suitable and clear regu- collate and aggregate regarding data quality, missing latory policy to manage this relationship with the elec- data, transmission errors, etc. tricity generation function to cope with possible critical situations. Furthermore, this initiative has to deal with regula- tory issues due to its relationship with the electricity G. Technical Prioritization Analysis and Smart Initiatives Metrics G.1 Key Points Summary of Technical ii. Performance indicator: Reduction of the time Prioritization and Metrics taken by maintenance crews to reach the fault location and related outage duration; The solutions identified for the NPT Smart Grid road- iii. Satisfactory threshold: 25%. map have been prioritized according to three timelines i.e. short term (within 5 years), medium term (within 10 b. Wide Area Monitoring System: years) and long term (within 15 years). i. Reason for positioning in the short-term: Besides the fact that NPT has developed a This time positioning is based on technical prioritization and pilot project, WAMS is a solution that could it is aimed at addressing the pressing and urgent needs as impact on some of the others and aims to quickly as possible. Therefore, the technical approach used solve a large number of issues; to perform such prioritization is a good starting point for the design of a phased roadmap but it is not exhaustive. ii. Performance indicator: (a) voltage collapse pre- The proposed NPT Smart Grid roadmap will be finalized vention, (b) prevention of out-of-steps collapses; after application-specific cost-benefit and risk analyses iii. Satisfactory threshold: (a) 15%-35%, (b) 15%-35%. and observations related to various regulatory aspects. c. Substation Automation System (building/ The gap analysis performed in chapter ‘E’ has revealed upgrade of substations and building of the strict necessity of implementing some basic Remote Control Centers): enhancements of the transmission system before start- i. Reason for positioning in the short-term: This ing to deploy any Smart Grid technology. The technical is a NPT project that has already reached a sig- requirements definitively position these “pillars” in the nificant level of development; veryshort term (within 2-3 years) without the need of fur- ther evaluations. In the following paragraph ‘G.3’ a table ii. Performance indicator: Energy Not Served presenting a brief time positioning and cost estimation of (ENS) reduction per year for each substation these basic enhancements is proposed. equipped with SAS; iii. Satisfactory threshold: 450MWh. This chapter also presents the technical reasons for the time positioning of each initiative and some metrics for d. Lightning Location System: the evaluation of the success of the various Smart Grid i. Reason for positioning in the short-term: This solutions as follows: is considered as a short-term solution due to the criticality of the lightning problem in Vietnam; a. The key reason for the time positioning of each Smart Grid initiative; ii. Performance indicator: Percentage reduction of transient faults; b. The performance indicator for the evaluation of a successful implementation; and iii. Satisfactory threshold: 20%-30%. c. The minimum threshold of the performance indi- e. Metering Data Acquisition System: cator just mentioned. i. Reason for positioning in the short-term: Metering Data Acquisition System represents The Smart Grid initiatives proposed for the short term the enabling technology for the development are the following: of the electricity trading market; a. Fault Locator System: ii. Performance indicator: Mean square error between the value acquired by the meters and value cal- i. Reason for positioning in the short-term: The culated by the settlement for the same meter; NPT project is already underway and is quite independent of all the other initiatives; iii. Satisfactory threshold: 0.4%-0.8%. 103 104 Smart Grid to Enhance Power Transmission in Vietnam f. On-line Dissolved Gas-in-oil Analysis: iii. Satisfactory threshold: 0.7. i. Reason for positioning in the short-term: The b. Dynamic Thermal Circuit Rating: main benefits of this technology are presented i. Reason for positioning in the long-term: It would with recommendations to equip all new trans- be better to wait for the current rapid growth rate formers with this type of device (starting from of the transmission network to slow down in the first ones already planned to be installed); order to leverage this application on a large scale; ii. Performance indicator: Prevention of trans- ii. Performance indicator: “Ampacity” increases; former outages; iii. Satisfactory threshold: 5%–25%. iii. Satisfactory threshold: 80%. The Smart Grid initiatives proposed for the medium G.2 Technical prioritization structure term are the following: Having collected all the Smart Grid initiatives suitable for a. Static Var Compensator: the Vietnamese transmission system it is worth analyz- i. Reason for positioning in the medium-term: It aims ing their prioritization from a technical point of view. to solve the voltage instability problem, which is quite critical, but before installing SVCs a very In Figure 71 the different solutions have been positioned detailed feasibility study has to be performed; on the basis of the transmission system issues they aim to solve. Here, thanks to the descriptions of each solution pro- ii. Performance indicator: (a) 95% (1 σ) varia- vided in the previous chapter, a strict technical prioritization tion interval of voltage level of network “pilot of the initiatives is performed which describes the reasons nodes, (b) voltage collapse prevention; for their assignment in the short, medium or long term. iii. Satisfactory threshold: (a) +/-5% of the rated voltage, (b) 15%-35%. Expanding on the concept of “pillars” as a foundation for the Smart Grid, as introduced in section ‘E.3’, the same b. Geographic Information Systems: idea of construction has been developed in Figure 71, i. Reason for positioning in the medium-term: where the schema for the time positioning of the pro- The prior development of other systems like posed solutions is depicted. SAS or WAMS could be very useful to plan the implementation of this type of solution; The positioning of the proposed Smart Grid initiatives on different time scales refers to the rollout of these initia- ii. Performance indicator: Reduction of manage- tives. The aim of the technical prioritization is to present ment costs; the priorities and urgent needs which is why there is no iii. Satisfactory threshold: 10%–15%. indication regarding the time schedule. c. Power quality monitoring system: Furthermore, it is worth observing that the development i. Reason for positioning in the medium-term: of each Smart Grid initiative must not to be considered Power Quality is one of the challenges of the as an atomic action as full deployment may take a lot of Vietnamese transmission system but it is not time, but its partial output could enable a useful starting considered as one of the most critical; point for other Smart Grid solutions. ii. Performance indicator: Reduction of voltage dips; The rest of this chapter describes the different “levels” iii. Satisfactory threshold: 20%. of the construction, highlighting the technical reasons for the time positioning of each initiative and proposing The Smart Grid initiatives proposed for the long term are some metrics for the evaluation of the success of the the following: various Smart Grid solutions. a. High Voltage Direct Current technology: The pillar-based approach is divided into four “levels”: i. Reason for positioning in the long-term: The a. Very-Short term (within 2-3 years); interconnection with neighboring countries is not an urgent requirement; b. Short term (within 5 years); ii. Performance indicator: Increased load factor; c. Medium term (within 10 years); and Volume 1: Technical Analysis 105 FIGURE 71: TECHNICAL PRIORITIZATION AND REFINED SMART GRID ROADMAP Source: Authors d. Long term (within 15 years). necessary. The gap analysis, performed in chapter ‘E’, has identified the following basic building blocks (or ”pil- All the Smart Grid solutions are represented by green lars”) as fundamental: pillars, while the development of traditional technologies needed to underpin the upper levels are shown in light blue. a. Planning and AMS basic strategies improvements; These pillars have been introduced because, as stated b. State Estimation and N-1 Security Assessment; in chapter ‘F’, the majority of the Smart Grid initiatives c. Load-Frequency Regulation strategies improve- require parallel developments of many other systems for ments; support and/or integration with new technologies. A case in point is the example of the investments in the TLC sys- d. Protection Systems improvements; tem necessary for the full development of SAS or WAMS e. TLC system improvements. (see ‘F.4.3’ and ‘F.5.3’). The aim of this section is to detail the concepts shown in Figure 46 proposing a time positioning of these basic G.3 Time positioning of Transmission interventions and so planning the necessary “Trans- mission System enhancement” before starting the System enhancement interventions deployment of Smart Grid technologies. Figure 72 pres- ents the different developments (detailed in paragraph To reach an adequate technological level in the Vietnam- ‘E.3’) regarding the various ”pillars” on a hypothetical ese transmission system for enabling Smart Grid devel- timeline. opment a “Transmission System enhancement” is 106 FIGURE 72: TRANSMISSION SYSTEM ENHANCEMENT INTERVENTIONS TIME POSITIONING Smart Grid to Enhance Power Transmission in Vietnam Source: Authors Volume 1: Technical Analysis 107 This time positioning is a brief guideline based on the Such time positioning is complemented by a general information collected during the discovery activity and estimation of associated costs, based on the information the missions in Vietnam. These developments do not gathered and reliable assumptions regarding the Viet- require any preliminary activity and can start immedi- namese transmission system. ately. The time duration of the implementation process of the different developments is a conservative estimation, Toward this end, Table 15 presents the cost estimation of based on similar activities performed in other countries the Transmission System enhancement developments, (e.g. Italy). It could happen that such time durations will highlighting the assumptions made. It is worth underlin- be less than stated as some initiatives have already been ing that for some initiatives no costs are needed. In these planned or are underway. cases the proposed enhancements do not require real investments. TABLE 15: TRANSMISSION SYSTEM ENHANCEMENT INTERVENTIONS COST ESTIMATION PILLAR INTERVENTION COST ESTIMATION Negligible in the context of the initiatives already Implement local automation strategy in underway for setting-up substation automation stations with three autotransformers systems. Verify the design of neutral reactance in Negligible in the context of the current work in substations where a high percentage of Planning and Asset progress on network maintenance activities. unsuccessful single pole reclosing occurs Management System basic strategies improvements The swapping of 30 breakers (at critical points) at Complete the substitutions of all the a cost of $10,000 each results in a total spend of breakers in most critical areas $300,000. Complete the installation of reactors The installation of 20 reactors at a cost of $40,000 between busbars in critical areas each results in a total cost of $800,000. Complete roll-out of State Estimation Negligible in the context of the initiatives already algorithm underway for setting-up a new EMS system. Complete roll-out of N-1 Security Negligible in the context of the current work in Assessment procedure progress on setting-up a new EMS system. State Estimation and on-line N-1 Security Assessment Complete automation of State Estimation Total cost of $300,000 considering both software algorithm and on-line N-1 Security purchase and operator training program. Assessment procedure Complete roll-out of Dynamic Security Total cost of $300,000 considering both software simulation purchase and operator training program. Analysis of the primary Load-Frequency Total cost of this survey activity is estimated at Regulation of the system considering the $200,000. best set of power units to be involved Load-Frequency Regulation Complete roll-out of primary Load- For hardware and software installation the expense strategies improvements Frequency Regulation can vary from $30,000 to $60,000 for each power plant. Assuming installation in 40 power plants, Complete roll-out of secondary Load- the total cost would be between $1,200,000 and Frequency Regulation $2,400,000. (Continued next page) 108 Smart Grid to Enhance Power Transmission in Vietnam TABLE 15 (CONTINUED) PILLAR INTERVENTION COST ESTIMATION Complete a detailed survey of all installed Negligible in the context of the current work in protection systems progress on maintenance activities. Development of an installation strategy that Installing dual protection on 30% of lines at an could allow a consistent and incremental average cost of $5,000 each results in a total cost improvement of system reliability of $1,500,000. Protections System improvements Repairing 5% of protection systems at an average cost of $3,000 each results in a total cost of about Complete the interventions to either $150,000. repair or replace unsuitable or damaged protections Replacing 5% of protection systems at a cost of $5,000 each results in a total cost of $250,000. Support to provide inputs for SCADA State Estimation Negligible in the context of the current work in TLC system improvements progress on setting-up the telecommunication Support to provide inputs for Load- infrastructure. Frequency Regulation Source: Authors G.4 Reasons for technical can be very complex and it is strictly dependent prioritization and metric on the functions developed using PMU data. For example, the evaluation of a voltage stability- identification monitoring feature based on WAMS can be con- sidered successfully implemented if it helps to , named ”Base for Smart Grid initiatives The first “level” prevent 15%-35% of voltage collapses. The per- development” , rests on the five “pillars” described in centage depends on the topology of that portion paragraph ‘E.3’. Upon this “level” or base it will be pos- of the network involved in the voltage instabil- sible to begin developing in the short-term the following ity events. The evaluation of a transient stability Smart Grid initiatives: monitoring function on WAMS can be considered successfully implemented if it helps to prevent a. Fault Locator System. The NPT project is 15%-35% of power plants out-of-steps. As in the already underway and is quite independent of voltage collapse case, the percentage depends all the other initiatives. It can contribute to time on the topology of the portion of the network and cost reduction of asset maintenance of the involved. most critical areas of the network with a relatively few number of components. In order to evaluate c. Substation Automation System (building/ the success of the FLS initiative, it is worth mea- upgrade of substations and building of suring the reduction of the time taken for main- Remote Control Centers). This is a NPT proj- tenance crews to reach the fault location and ect that has already reached a significant level related outage duration. The FLS application can of development. It has been conducted in syn- be considered satisfactory if after its implementa- ergy with building of Remote Control Centers tion such times are reduced by 25%. for unmanned substations since Remote Con- trol Centers constitute a pre-requisite to exploit b. Wide Area Monitoring System. Besides the fact at best SAS equipment in electrical substa- that NPT has developed a pilot project, WAMS tions. Their realization is fundamental to posi- is a solution that could impact on some of the tion such SAS initiative in the short term. In others (e.g. Dynamic Thermal Circuit Rating) and order to support remote control the develop- aims to solve a large number of issues (e.g. volt- ment of a communication backbone connect- age and transient stability, defense plans, etc.). ing all the substations under NPT management The evaluation of the success of WAMS initiative Volume 1: Technical Analysis 109 is a fundamental requirement. The status of the of the transformer it protects and no particular deployment to date is discussed and some rec- analysis has to be performed before installing this ommendations are made in order to optimize the equipment on new transformers (as mentioned benefits of this solution, especially with regard to in paragraph ‘F .11’). Furthermore, NPT is already interoperability and prerequisite telecommunica- started to develop this initiative and it is worth to tion system improvements. Fully digitalized sub- continue investing in this type of technology on stations, remote terminal units, remote operation all the transformers that will be installed in Viet- and supervision represent the key elements for nam in the next years. Therefore this initiative has the success of SAS initiative. As described in the been positioned in the short term. On the other international experiences section (see section hand, their use with the existing transformer ‘D.2.6’), the key performance indicator (KPI) for fleet instead will require the identification of the the evaluation of this application is the reduction most critical and valuable ones that need to be of Energy Not Served (ENS). A SAS implementa- protected. In fact equipping current transformers tion can be considered successful if the average with these monitoring devices requires a detailed value of annually prevented faults per substation investigation in order to evaluate the time needed equipped with SAS is above 1.5. Considering an to gather data for the characterization of typical average value of 300  MWh of load losses per transformer behavior so as to eliminate false fault event, this value corresponds to an average positives. The DGA installation initiative can be ENS reduction of 450 MWh per year for each sub- considered successful if using these monitoring station equipped with SAS. systems a consistent prevention of transformer outages is achieved. A satisfactory value is a d. Lightning Location System. This is considered reduction by 80% in the number of faults. as a short-term solution due to the criticality of the lightning problem in Vietnam. Furthermore The ”First step in Smart Grid development” will have the installation of a Lightning Location System been reached following the development of the projects requires quite a long lead time which is why, if described above. Upon this “level” it will be possible the proposed solution is approved by NPT, it to begin developing in the medium-term the following should begin as soon as possible. After Transmis- Smart Grid initiatives: sion Surge Line Arresters installation (guided by Lightning Location System data analysis). The a. Static Var Compensator. This aims to solve the KPI of the initiative is a reduction of faults in the voltage instability problem, which is quite critical, range of 20%-30% which would be considered but before installing SVCs a very detailed feasibil- satisfactory. ity study has to be performed. Making the right choice regarding the locations of SVC devices in e. Metering Data Acquisition System. The NPT a fast growing network like the Vietnamese one project is already underway and it is important will prove to be really challenging. To evaluate to reach a full rollout of this initiative in the near the SVC installation performance it is impera- future because it represents the enabling tech- tive to measure the variations of voltage level of nology for the development of the electricity the most important network nodes (called “pilot trading market. The simultaneous installation of nodes”). If 95% (1 σ) of such variations is within SAS may be useful for facilitating the data acqui- +/-5% of the rated voltage the result can be con- sition process of the Metering Data Acquisition sidered satisfactory. Furthermore, as for WAMS System. It is worth to consider that for the full evaluation, a SVC can be considered to be operat- deployment of such initiative a careful investiga- ing successfully if it helps to prevent 15%-35% tion of all the regulatory aspects is fundamental. of voltage collapses in the portion of the network To evaluate the success of the Metering Data influenced by its effects. Acquisition System initiative it is worth measur- ing the mean square error between the value b. Geographic Information Systems. The prior acquired by the meters and the value calculated development of other systems like SAS or WAMS by the settlement for the same meter. A satisfac- could be very useful to plan the implementation tory value would lie in the range 0.4%-0.8%. of this type of solution considering the largest possible number of applications that would ben- f. On-line Dissolved Gas-in-oil Analysis. It is pro- efit from this initiative. In order to evaluate the posed that all new transformers have this device success of the GIS initiative, it is worth measur- installed, as its cost is about 2-3% of the value ing the reduction of management costs of the 110 Smart Grid to Enhance Power Transmission in Vietnam network. A satisfactory value for such reduction All of the above has to be considered as a technical priori- would be in the range of 10%–15%. tization of the Smart Grid initiatives and that the process of positioning the solutions on the timeline was evalu- c. Power quality monitoring system. Power Qual- ated on the basis of whether: ity is one of the challenges of the Vietnamese transmission system but it is not considered as a. A similar project is already ongoing even as a pilot one of the most critical. A suitable KPI is the per- project (e.g. Substation Automation System or centage reduction of voltage dips where a value Wide Area Monitoring System); above 20% can be considered satisfactory. b. A project is a prerequisite for other ones (e.g. a The ”Second step in Smart Grid development” will have full Substation Automation System implementa- been reached by this stage and with the implementation tion as a useful base for Metering Data Acquisi- of the Metering Data Acquisition System the base for tion System development); and the electrical market deployment will have been created. c. The urgency of the transmission problems that Upon this “level” it will be possible to begin developing a project aims to solve is high or low (e.g.: Light- the long-term Smart Grid initiatives as follows: ning Location System). a. High Voltage Direct Current technology. It is This technical approach is a good starting point for the worth developing this type of technology, which design of a phased roadmap but it is not exhaustive. could be useful for the interconnection with Thus, at the time of this report it is too early for the full neighboring countries. This topic is not urgent and development of a precise GANTT of the implementation HVDC represents one of the possible solutions plan without having the results of the Cost-Benefit Analy- to be evaluated but is not the only possibility. To sis, which evaluates some possible development scenar- evaluate the success of an HVDC link installation ios of the proposed initiatives and the installation times. it is worth measuring its load factor and a value above 0.7 can be considered satisfactory. The final prioritization of the Smart Grid initiatives will be b. Dynamic Thermal Circuit Rating. NPT has defined after the Cost-Benefit Analysis, which will also already planned the development of such an appli- evaluate the economic parameters in order to under- cation, so the implementation of a pilot project stand the real added value of each solution. will be a good starting point. However, it would be better to wait for the current rapid growth Finally, the metrics identified for the evaluation of the rate of the transmission network to slow down success of the various Smart Grid solutions is a good in order to leverage this application on a large starting point for the Cost-Benefit Analysis because it will scale. According to international experience the be exploited for evaluating the benefits of the initiatives. dynamic ratings are typically 5% to 25% higher The performance indicators proposed for each applica- than conventional static ratings. So, if on the tion are summarized in the following Table 16. lines where the DLR is applied the “ampacity” increases from 5% to 25% the results of DLR It is important to note that these metrics consider the implementation will be considered satisfactory. Smart Grid solutions only from the technical point of view. The complete list of KPIs will be proposed in the The ”Full development of Smart Grid technologies for third report, after the evaluation of Cost-Benefit Analysis Vietnam’s transmission system goals” will have been results. reached following the development of the initiatives described above. Volume 1: Technical Analysis 111 TABLE 16: TECHNICAL METRICS IDENTIFIED FOR SMART GRID SOLUTIONS SMART GRID SOLUTION PERFORMANCE INDICATOR SATISFACTORY THRESHOLD Reduction of time taken to attend fault site by maintenance crew and Fault Locator System related outage duration 25% Voltage collapse prevention 15%-35% Wide Area Monitoring System Out-of-steps prevention 15%-35% Energy Not Served (ENS) reduction per year for each substation Substation Automation System equipped with SAS 450MWh Lightning Location System Percentage reduction of transient faults affecting the lines 20%-30% Mean square error between the value acquired by the meters and the Metering Data Acquisition System calculation by the settlement process for the same meters 0.4%-0.8% 95% (1 σ) variation interval of voltage level of network “pilot nodes” +/-5% of the rated voltage Static Var Compensator Voltage collapse prevention 15%-35% Geographic Information Systems Reduction of management costs 10%-15% Power quality monitoring system Percentage reduction of voltage dips 20% High Voltage Direct Current technology Load factor 0.7 On-line Dissolved Gasinoil Analysis Reduction in the number of faults 80% Dynamic Thermal Circuit Rating “Ampacity” increase 5%-25% Source: Authors Annex 1. Functional and Organizational View of Transmission Systems Worldwide In order to implement the Smart Grid initiatives in the In this chapter the structure of different kinds of trans- most efficient way, it is important to define the func- mission utility will be analyzed both from the functional tions central to an Electricity Transmission System and and organizational point of view. In the first place it is the viable models for the organizational structure of the important to identify all their functions and the definitions transmission operators. This approach will make it pos- provided by CEER (Council of European Energy Regula- sible to identify the various contributors to the transmis- tors) best describe these functions (see [27]). sion system and to understand their interactions within the context of the selected Smart Grid applications. The CEER model is the European benchmark for electric- ity transmission system operators and this approach has In general terms, it is important to note that a transmis- been chosen because it offers a complete description of sion company may assume the role or roles as follows: transmission utility duties and supports the introduction of the principal organizational structure models. Further- a. System Operator of the network; more, reviewing the functional view of a transmission system in the light of the European experience could be a b. Asset Manager of the grid; and useful point of reference for the Vietnamese experience. c. Both the above roles. The transmission systems worldwide are organized in a. Functional View of Transmission different ways depending on the specific market struc- Systems tures of the country under consideration: A transmission utility has the fundamental duty to a. In the USA, there is Regional Transmission Orga- ensure the stability of the electrical system (either inter- nizations (RTO) to manage the transmission grid connected or not), in order to guarantee that energy can on a regional basis throughout North America be transmitted from generators to distribution networks. (including Canada). FERC Order No. 2000 delin- eated twelve characteristics and functions that an The basic assignments of a transmission utility are: entity must satisfy in order to become a Regional Transmission Organization. a. The provision of open access to the transmission b. In Europe there are Transmission System Opera- system; tors (TSO) which are entities entrusted with b. The monitoring and control of the system opera- transporting energy on a national or regional tions in order to ensure energy balance, conges- level, using fixed infrastructures. The term TSO tion management and generation scheduling; was defined by the European Commission. The certification procedure for Transmission System c. The acquisition of ancillary services, such as dis- Operators is listed in Article 10 of the Electricity turbance reserves and voltage support; and and Gas Directives of 2009. d. The planning and the approval of the requests for c. In several Latin American countries, the trans- maintenance of the transmission and generation mission operators have different functions facilities. according to the market, which range from the transmission activity to planning and investing. CEER distinguishes six important functions or roles, these are: This divergence leads to different naming conventions for a. Market Facilitation; the companies depending on their specific chosen func- tion. In order to avoid misunderstandings in the following b. System Operation; sections, the term “transmission utility” will be used as c. Grid Planning; a generic reference for companies that manage a trans- mission system. d. Grid Construction; 112 Volume 1: Technical Analysis 113 e. Grid Maintenance; and a.ii. System Operation f. Grid Ownership/Financing. System operation functions have to: The first function is performed in those countries with a. Ensure real-time energy balance; a well-developed electricity market. In these cases sys- b. Manage congestion; tem operators administer spot and real-time balancing of energy markets. These operators generally also carry out c. Schedule and dispatch generation; metering, accounting, settlement, and billing for the mar- d. Perform failure analysis and detection; kets, but may additionally initiate, enforce or administer market instruments related to congestion management, e. Manage the availability and coordination of pre- supply safety and load control. ventive and reactive remedial actions; and f. Acquire ancillary services, such as primary/sec- Then, there are System Operation and Grid Planning, ondary load-frequency regulation reserves and which are strategic and have both a real-time and long- VAR/voltage support. term impact on system performance. On the other hand, the functions of Grid Construction and Maintenance are All of these duties are aimed at maintaining the techni- typically also identified as Asset Management. However, cal quality and balance within a coherent electricity sup- Grid Ownership is normally connected to regulatory and ply system and for ensuring that the necessary supply institutional practices. capacity for the regulation of the system is available. a.i. Market Facilitation System Operation also has to deal with the limitations of the existing grid, the daytoday management of network The activities for this function involve gathering and col- functionality (including personnel safety and equipment lating information regarding costs and direct resources security), coordination with operations management of related to the management, facilitation or administration neighboring grids, coupling and decoupling in the net- of marketplaces. These include: work of all the players acting on the “live” grid. a. Measurement; a.iii. Grid Planning b. Calculation and dissemination of price tariffs (node prices, price zones); This function is aimed at carrying out the analysis, plan- ning and drafting of grid expansions and network installa- c. Preparation of annual surveys and forecasts for tions and includes the management of all the necessary use by the market’s current and potential players internal and external human and technical resources. and to illustrate compliance with public service obligations; Moreover, grid planning is responsible for system-wide d. Information for settlement of claims and contract coordination and enhancing the general competence of flows from exchanges; the TSO. This function has also to take into account costs for research, membership of research organizations and e. Backup agreements; and sector organs, development and testing (related to func- f. Research and development into market function- tioning of the transmission system), coordination with ing, mechanisms and contracts. other grids and stakeholders. Market facilitation may also include the responsibilities related to the flow of information to relevant markets a.iv. Grid Construction (green certificates, renewable fuels, DSM, DER, prefer- The grid constructor has the duty to implement the plans ential feed-in tariffs). originating from the grid planning function. This duty involves tendering for construction and procurement of Costs and revenues related to transitional or permanent material, interactions, monitoring and coordination of retail engagements, such as procurement, billing, losses contractors or own staff performing ground preparation, and resale of energy are considered specific cases of disassembly of existing installations (if required), tempo- market facilitation. rary site constructions and installations, installation of equipment and infrastructure. In particular, all expenses related to site selection and environmental impact 114 Smart Grid to Enhance Power Transmission in Vietnam analyses are classified as grid construction costs, since or spot markets. This section describes various possible they normally arise during the commissioning. structures highlighting their strengths and weaknesses. The main types of companies that might be included a.v. Grid Maintenance within a transmission utility structure are [28]: The Grid Maintenance function involves all the preven- tive and reactive services concerning the assets, the a. A full-service TSO, known as Transco in the US, is staffing of facilities and the replacement of degraded an independent company that combines ownership or faulty equipment. Both planned and required mainte- of the grid and responsibility for system operations of nance are included, as well as the direct costs of time, the grid. It may be a for-profit or not-for-profit entity. material and other resources to maintain grid installations. b. A Transmission Owner (TO), known as Gridco It also includes field assessment and reporting on the actual in the US, is an independent company that owns condition of equipment and their management, planning of the grid, but does not have responsibility for oper- operations and of data-collection/evaluation, lawn mow- ating the system. It works in conjunction with a ing, tree cutting and any required emergency actions. system operator and it too may be a for-profit or not-for-profit entity. a.vi. Grid Owner/Financing c. An Independent System Operator (ISO) has The grid owner is the possessor of the transmission grid responsibility for managing the use of the grid and its function is to ensure the long-term cost efficient and coordinating the spot market. financing of the network assets and to administer all the cash flows related to their management. All the types of companies identified do not have the ownership of generation and retail supply. The ownership separation of TO/ISO from generation and distribution aims to eliminate potential conflicts of interest. b. Organizational View of Transmission Utilities Figure 73 shows the three most significant models of organizational structure; it indicates the transmission There is a continuing debate about the best model for organiz- utility functions performed by each type of company ing the coordination and control of the transmission system, and identifies a European example of each of them that including dispatch and coordination of energy balancing exploits such a model. FIGURE 73: TRANSMISSION SYSTEMS: FUNCTIONS AND ORGANIZATIONAL MODELS Source: e3GRID, 2009, (24) Volume 1: Technical Analysis 115 In the full-service TSO model SO and TO functions are integrated with the operation of organized wholesale under common ownership/control. In this configuration markets for energy, frequency regulation and operating transmission is a monopolistic service, so both it and its reserves and is responsible for ensuring that the opera- prices must be regulated. Regulation of the transmission tions are both economical and reliable. provider is a substitute for competition, and therefore, its core objective is to prevent the transmission provider The presence of a separate ISO is naturally required from charging customers a price for access and use that when there is more than one TO and in general it is con- would be uncompetitive in an open deregulated market sidered more politically acceptable compared to a full- model. This structure is typically combined with transpar- service TSO. ent organized public markets for energy, network support services and congestion management that are used by On the other hand, the responsibility for the integrated the transmission utility to fulfill their responsibilities. planning of transmission investments is increased in a separate ISO. International experiences demonstrate In theory this represents the ideal model. The econom- that ISOs with “deep functional” responsibilities that ics of transmission investment and the scope and scale are well integrated with wholesale markets work reason- economies of service provision ensure that this will be ably well, but it is really challenging as inefficiencies from the case for the foreseeable future. Furthermore the the absence of vertical integration with TO functions can existing examples of such a model have functioned well lead to problems with coordination of maintenance and in all dimensions. investment planning and complicates the governance and regulation of the ISO. In this scenario the responsi- The main strength is the complete integration of all the bilities of the ISO tend to expand over time to deal with Transmission Utilities function that in most cases facili- these inefficiencies and TOs become passive owners of tate the development of applications in which both TO regulated assets that march to the ISOs orders. and SO functions are deeply involved. These weaknesses are the reason why the full-service On the other hand, it requires well-developed regulatory TSO represents a reliable future scenario for those mechanisms and may require some functional sepa- countries in which there is only one TO and the pres- ration especially in cases where there are unregulated ence of a separate ISO in not compulsory. In this case lines of business (e.g. interconnections). the example of the evolution that took place in Italy in 2005 is significant. At the time the Italian TSO passed Instead, a separate ISO owns the control room and com- from a structure composed of GRTN (SO) and Terna (TO) munications facilities and it is independent from all mar- to a single full-service TSO (Terna) within which the mar- ket participants, transmission and distribution owners. ket facilitation function was subsequently managed by a single entity. The changes to the organizational structure It is responsible for all aspects of reliable and economi- and the development of the Italian transmission system cal system operations and interconnection and may will be described in paragraph ‘D.2.1’, together with the cover facilities of multiple transmission network own- motivations for such an evolution. ers (some vertically integrated). Moreover, it is typically Annex 2. Vietnamese Transmission System The previous chapter examined a model for the struc- All energy relevant institutions are headed by the Minis- ture of a transmission utility, so, before dealing with the try of Industry and Trade (MOIT) which has the role of pol- analysis of the Vietnamese issues and challenges (inves- icy maker for the whole national power sector and stands tigated in ‘Annex 2b’), it is worth analyzing the organiza- above all other relevant energy agencies and generation tion of the Transmission System in Vietnam in the light systems. It is responsible for the advancement, promo- of the principles discussed in the preceding sections. In tion, governance, regulation, management and growth of the following section, this analysis will be important to the electrical industry in Vietnam. describe the roles played by the different functions of the utility in implementing projects for Transmission System Directly dependent on the Ministry of Industry and Enhancements and Smart Grid initiatives. Trade there is the Institute of Energy (IE), which is the main organization doing research and contributing to the national energy policy. Its main contributions are studies on a. Vietnamese Transmission System national energy strategies, policies and development plans Organization and consulting activities on the formulation of national strategies and policies on energy and power develop- Figure 74 [29] shows the roles and relationships of the ment. Among all the plans prepared by IE there are: most relevant players in the implementation of the Viet- namese Smart Grid initiatives. FIGURE 74: VIETNAMESE ENERGY RELATED ORGANIZATION Source: Annex POWER, 2013, (25) 116 Volume 1: Technical Analysis 117 a. The National Energy Development Master Plan; The Electricity Regulatory Authority of Vietnam (ERAV) was established in October, 2005 as an entity under b. Monitoring and assessment of Power Devel- MOIT, to conduct: opment Master Plan implementation process, as Advisor to Ministry of Industry and Trade on a. Development and regulation of power markets; steering measures; b. Economic regulation (electricity pricing); c. Preparation of National Power Development Mas- ter Plan; c. Monitoring supply/demand balance to promote security, efficiency and conservation; and d. National Renewable Energy Development Mas- ter Plan; d. Licensing and Dispute resolution. e. Human resource development plan for the energy Then there is the Vietnam Electricity (EVN), which is the sector; main business unit of the Vietnam Electricity Group and f. Power development plans for territories, prov- includes: inces, cities, industrial zones and residential areas throughout the country and foreign coun- a. Production, transmission, distribution and trading tries in the region; of electricity; g. Plans for grid-connection of power plants, power b. Administration of power production, transmis- transmission lines, interconnection with power sion, distribution in the national electricity sys- systems of neighboring countries; tem; import and export of electricity; h. Development plans for thermal power, hydro- c. Investment management and investment power power and nuclear power; projects; and i. National rural electrification master plan; and d. Management, operation, repair, maintenance, overhaul, renovation, upgrading of electrical equip- j. Research on compiling procedures and norms to ment, and electrical research and experiments. serve energy sector development. EVN structure (depicted in Figure 75) is characterized These duties highlight the key role in the planning func- by a vertical integration of Generation, Transmission and tion exerted by the IE within the structure of the Viet- Distribution. namese Transmission System. In the following sections, when referring to the planning function for the imple- The two companies that comprise the transmission level mentation of Smart Grid initiatives it will be important to deserve particular attention out of all the different EVN take into account the strategic role of the IE. structural components and they are: FIGURE 75: THE VERTICAL-INTEGRATED STRUCTURE OF VIETNAMESE ENERGY SECTOR Source: Annex POWER, 2013,  (25) 118 Smart Grid to Enhance Power Transmission in Vietnam a. The National Power Transmission Corporation operator, represented by NLDC, the planning organi- (NPT), which was established through the merger zation represented by IE and the single transmission and reorganizing of four transmission companies owner, represented by NPT. and three project management boards. Its main role is Asset Management and in this regard it It is worth noting that the transmission utility of the Viet- is responsible for installation, maintenance and namese organization is quite similar to the Italian model control of all the equipment of the transmission up to 2005, as depicted in Figure 73. However, a closer network. look shows that the Vietnamese model is a little more complex, as it involves three players as opposed to just b. The National Load Dispatching Center (NLDC) is the two in the Italian case. mainly concerned with System Operation. NLDC is responsible for dispatching of generation, man- The absence of vertical integration in this kind of structure aging congestion, performing failure analysis and is one of the reasons why the Italian transmission sys- detection, controlling availability and coordina- tem evolved into a single full-service TSO, as discussed tion for preventive and reactive remedial actions. in paragraph ‘D.2.1’. This does not imply or suggest that It is important to underline that NLDC, unlike the Vietnamese transmission utility has to follow the Ital- NPT, has no direct control over the transmission ian example, but it will be important to take into account network. Therefore, all actions determined by the peculiarities of their organizational structure when system operation functions cannot be executed addressing Smart Grid solutions. directly, but must be communicated to the NPT, which then performs them on the real transmis- It is worth emphasizing this issue because implementing sion system. Smart Grid initiatives often involves more than just the one function of a transmission utility and, as in the Viet- Thus the models shown in paragraph ‘Annex 1b’ could namese model, more than one player. This may lead to be mapped to the Vietnamese Transmission System greater complexity in the development of projects. as shown in Figure 76, with an independent system FIGURE 76: VIETNAMESE TRANSMISSION SYSTEM ORGANIZATION Source: Authors Volume 1: Technical Analysis 119 In order to promote the successful development of the Furthermore, from the discussion with NPT technicians Smart Grid roadmap a careful specification of the tasks and the consequent analysis of the grid single line dia- for each player and a definition of the policies dictating gram, the current Vietnamese topology looks highly their shared interactions will be key to the ultimate suc- meshed. This structure leads to a very high fault current cess of the initiative. that exceeds the rated current of circuit breakers with consequent failures affecting their opening. This happens on the 220 kV network where most of the circuit break- b. Main Vietnamese issues and ers have a rated current of 40 kA. challenges The current section explores the problems of network In order to choose the most suitable and effective Smart topology (transient and voltage stability, short circuit Grid initiative for Vietnam, it is fundamental to identify level, etc.) while some solutions in terms of both the its critical transmission system needs, starting with an Transmission System Enhancement initiatives (paragraph analysis of the issues and challenges. ‘E.3’) and the Smart Grids projects (chapter ‘F’) have been proposed. During the discussions with NPT technicians several issues were highlighted, basically relating to on-going b.ii. 500kV limited transient stability problems associated with the management and opera- tion of existing assets. These problems were described The first limitation caused by the present Vietnamese in an earlier report and the most relevant ones are sum- network topology regards transient stability. This primar- marized in the following section. ily concerns the 500kV network, where even a single dis- turbance (such as the tripping of a 500kV circuit breaker) is likely to exceed the stability limit and cause the system b.i. Network topology issues to become unstable. In May 2013 the southern region of Vietnam experienced a massive power outage. This was caused by a truck that, NLDC simulations have shown that instability can occur while delivering a tree, damaged a line in the national when the line is heavily loaded (1,200MW for a single power grid (500 kV) in New Bình Du’o’ng City urban area. line and 1,700MW for two parallel lines) and the insta- The transmission system was not compliant with the N-1 bility risk is increased when the Da Nang, Pleiku 500kV security criterion, so the truck incident led to a cascade substations operate with inadequate devices (i.e. lacking effect causing a wide-ranging blackout across twenty one or more circuit breakers) [30]. two provinces. This is a typical case where a small inci- dent has a major knock-on effect causing significant dam- The system’s transient stability margin significantly age. This event also revealed that there was no insurance increases when most of the substations are operated coverage for the assets of the electrical system to com- with the 380/200 kV transformers connected, especially pensate for unexpected outage events and the associ- when the link is operating with two complete parallel cir- ated damage. cuits. With two parallel lines, the voltage and transient stability limits are both improved. In addition to this serious event, there have been other lower impact incidents that have occurred with some b.iii. Voltage Stability, Profile and Support/ frequency on the network and reveal major topology Reactive Power Balance weaknesses. The current network topology includes several shunt First of all the Vietnamese network structure reflects the devices to manage and optimize the generation of reac- geographical shape of the country, which is long and nar- tive power on the various voltage level networks. row. This has influenced the location of the generation sources most of which are concentrated in the North and On the 500 kV network shunt reactors are installed for in the South. Thus, Vietnam is characterized by a high compensation of the transmission lines. On the 110 kV North-South power flow, over the 500kV backbone links system, several shunt capacitor banks are present for [30]. This imposes operational limitations and exposes the generation of reactive power and voltage support. the system to a high risk of instability, especially from These systems allow discrete reactive compensation, the point of view of transient and voltage stability. through switching capacitor banks in response to net- work conditions. 120 Smart Grid to Enhance Power Transmission in Vietnam The use of circuit-breakers equipped with Point Of b.iv. Short Circuit Level Wave (POW) systems (switch-sync relays) may allow This issue mainly impacts on the substation equipment a smoother operation of these compensation systems rating and the definition of the 500/220 kV step-down and the reduction of transient disturbances following a transformer characteristics (rated power, short circuit switching (opening or closing) event. Unfortunately, even impedance, short circuit resilience, paralleling of the with this POW feature it would not be possible to sup- units). port a rapid and continuous adjustment of reactive power injection. The use of specific components, devices and provisions to limit the short circuit current are related to addressing Therefore, one of the main side effects of using such particular needs and requirements. discrete shunt compensation devices is the difficulty of ensuring reliable voltage regulation. This is particularly NPT has already envisaged the possible use of a series true for the long transmission lines and highly variable reactor in combination with bus-bar sectionalization in loading conditions, due to the unbalanced distribution of order to contain the short circuit level within design limita- load and generation. tions. This solution impacts the operational security of the system, in particular during peak load conditions and when The analysis of the documentation on the Vietnamese grid faced with contingency/transient occurrences, since the has identified various operating conditions in which the volt- system could then experience stability problems. age tends to fluctuate within a wide range of values. Only the execution of a detailed load flow and contin- Operating conditions are reported where the minimum gency analysis can verify if the proposed configuration threshold voltage of 0.9 p.u. is exceeded during peak is suitable for ensuring the limitation of the short-circuit hours, with heavily loaded 500 kV lines and, on other current without impacting on the system’s operation. occasions, with a significant high voltage level during low This calculation also aims to determine the proper split- load hours, public holidays or at night. ting points, ensuring the correct generation/load balance and the fulfillment of transmission capacity constraints Both the above cases, i.e. relatively high or very low volt- for various sections of the system, all whilst ensuring the age levels, could cause non-optimal working conditions parallel operation of the system as a whole. for the transmission network, with a significant increase in transmission losses resulting in both thermal and There are some smart technologies that can provide a dielectric stresses of the system components. better operational approach for this problem whilst ensur- ing a more resilient configuration of the system. In prin- Moreover, whenever the system operates at loads that ciple the use of the advanced assessment features of an are too close to the operational voltage limits the net- EMS (see E.3.2 which looks at State Estimation and N-1 work operator is forced to change the configuration of Security assessment) will allow the precise identification the system, leaving the network in a critical condition of operating conditions and constraints of the system with loss of redundancies and reduction of operating and therefore allow the correct compartmentalization of margins which in turn reduces the system’s resilience to the 500/220 kV network. device or line failures. Moreover, the adoption of Special Protection Schemes The use of Static Var Compensator (SVC) devices and the (SPS) will also allow fast reconfiguration of the grid appropriate tuning of the relevant control systems in par- (e.g. contingency-based remedial action schemes and ticular combined with the introduction of power oscilla- advanced remedial action schemes) after a potentially tion damping functions, will help to stabilize the network, dangerous event. while increasing the transmission capacity, optimizing the voltage profile and consequently also reducing losses along the lines. This topic is addressed in section ‘F.7’. b.v. Lightning Performance of exposed 220 kV lines In particular, a suitable reactive power infrastructure on the 500 kV transmission grids will help to maintain Some sections of double circuit lines located in the north- adequate voltage profiles and reduce the susceptibility ern area of the NPT grid have problems due to the fact of the system to the risk of voltage instabilities, which that the single-phase auto re-closure cycle fails owing to might occur in conditions of high load and particularly the presence of a secondary arc-current that precludes with reduced voltage at the receiving end of the system. the extinction of the arc at the fault location. Volume 1: Technical Analysis 121 A possible solution being considered by NPT is the instal- of the 500 kV lines. Thus, the Vietnamese power system lation of suitable Line Surge Arresters (LSAs) in order to was lacking an appropriate special protection scheme increase performance of these lines in the presence of rather than suffering from an inadequate under fre- lightning. The technical literature shows several examples quency load shedding scheme. If the system was not of the application of LSAs to increase the performance of fulfilling the N-1 security criterion, a SPS remedial action the OHTLs, typically for lower voltages (60, 110, 132, 150 should have been in place to guarantee a swift reaction kV), but it has also been known to work for 220 kV and to line tripping. higher system voltage levels. Positive results can be achieved providing that the b.vii. Load-Frequency regulation selected solution is developed on the basis of a detailed Improvements technical analysis with the choice of the type (i.e. gap or The Vietnam Primary Load-Frequency regulation descrip- gapless) and the location of LSAs made according to the tion issues were discussed with NPT technicians during configuration of the line as well as the correct identifica- the discovery process. tion of those towers with the highest probability of being struck by lightning (using suitable insulation coordination Primary frequency regulation is crucial to maintain reli- software tools). Additionally the analysis would also need able operation of the system after an incident. The pri- to identify those areas most exposed to lightning with mary control center must maintain the frequency within relevant Ground Flash Density figures and definitions of the allowed range by increasing (or decreasing) the gen- the type and value of the grounding parameters of the erated power, preventing the frequency drop (or raise). In OHTL towers. case of limited contingencies, primary control must han- dle the imbalance caused by events without any under- There are also some smart applications that can be lev- frequency load shedding or generation tripping. Like eraged to address this specific issue. In principle the other protection equipment, the primary control is the implementation of a Lightning Monitoring and Detection first line of defense of the network against disturbances. system will allow the operator to identify the occurrence Like protection devices it relies only on local measure- of hazardous conditions in advance, and then facilitate ments (frequency at generator’s terminal) and must react possible actions for system reconfiguration and power in a matter of seconds. flow re-dispatching, in order to minimize the impact of an outage of a line adversely affected by a lightning strike. Presently this type of regulation is achieved by using a single hydro power plant at a time, chosen from a set of b.vi. Defense Plan Improvements five possible hydro power plants depending on network conditions. Although no particular concerns about fre- The Vietnamese blackout in May 2013 revealed the weak- quency stability has been highlighted by NPT technicians, nesses and/or failures in the current protocols for reme- some enhancements of the Primary Load-Frequency reg- dial actions in the event of unexpected massive outage. ulation should be considered in the near future. The system was not fulfilling the N-1 Security criterion as neither the defense plan nor the protection scheme (if b.viii. Miscoordination of Protection Systems any) had been able to counteract the initial fault. Given the current network topology and the need to main- tain a complete “meshing” of the existing stations, any If the Vietnamese power system experiences an under miscoordination or malfunction of protection systems frequency load shedding, its remedial actions would be can potentially lead to the loss of a large portion of the completely inadequate to face transient instability of such system with the attendant risk of general system instabil- severity. The reasons for the failover deficiencies during ity and blackouts or brownouts. This can happen both in such significant events must be investigated. Likewise, if the case of intervention of back-up functions following a generation shedding scheme is operating on the grid, the failure of the base protection function/device or in the cause of its failover must be identified to address the the case of a failure of the first-line protection functions. most effective security enhancement. Some examples of problems caused by the failure of pri- Although, the grid topology and the other documented mary components (e.g. circuit breakers) that led to these incidents happened before 2013, it does suggest that the events were provided by NPT personnel. Various events most probable cause of the massive black out could have have been identified in which the origin of the shutdown been a cascade line tripping due to transient instability 122 Smart Grid to Enhance Power Transmission in Vietnam of part of the system is related to the malfunction or b.x. Time and cost reduction of asset miscoordination of the protection system probably due maintenance to interference and electro-magnetic compatibility issues on secondary signals. As stated in paragraph ‘Annex 2a’ above, Asset Manage- ment is one of the main responsibilities of the NPT and One of the on-going NPT development activities is actu- one of their most critical concerns is the time and cost of ally relevant to the definition of basic specifications for asset maintenance. protection and control systems to be installed in their new stations. However, it seems that the focus of this In particular after a fault, the time and costs necessary activity is essentially aimed at ensuring basic and com- for all the physical interventions, in the first instance, mon characteristics (i.e. interoperability) that will then depend on the time taken by field technicians to locate allow the NPT to interface systems provided by different the fault. There are different types of initiatives that could suppliers. The activity of defining these basic specifications be put in place to address this requirement. The num- should also include the definition of requirements to fully ber of faults can be significantly decreased by improving ensure compliance with electro-magnetic standards in Asset Management and Planning strategies and reduc- order to overcome the reported problems of the EMC. ing the risk of the protection systems miscoordination or malfunctioning in the first place. It is worth considering that the possible integration of smart technologies such as the adoption of systems It is possible to implement Smart Grid solutions aimed and advanced IED minimizes the use of traditional cop- at reducing the time and cost of asset maintenance. per cabling and maximizes the exchange of data/signals Towards this end NPT has begun to implement a Fault via fiber optics thus removing the risk of RFI disturbance Locator System (FLS) that, thanks to its high precision and consequent operational failure. This would have the in fault localization, can improve the efficiency of inter- additional benefit of integrating easily into any proposed vention for damaged components and thus significantly Smart Grid environment. improve the mean time to repair. b.ix. SCADA & Remote Control Centers b.xi. Power Quality Several new technologies are either in place or in the In the Grid Code, the power quality reference levels and design approval phase within the EVN structure for the applicable limits are clearly defined for the transmission creation of a remote management system for the net- network (in particular harmonic distortion and flicker). In work. These initiatives range from the installation of RTU/ reality, at the moment there is no monitoring of power Gateways in existing substations, required for the inter- quality on the Vietnamese network and nor does there facing of local devices, the installation of communication appear to be any plan for incorporating monitoring capa- networks/WANs and then SCADA/EMS plus SCADA for bilities in the near future. Even the most basic analysis of remote control centers (both for the PTC areas and cen- availability levels guaranteed for the transmission system tral NPT remote control center). appears not to have been done in a systematic way. General requests from NPT are related to the identifica- The creation of an infrastructure for monitoring the level tion of criteria, principles and functionalities to be pro- of power quality could be a starting/enabling element for vided for the set-up of a remote control center. Prior to identifying and monitoring the level of functionality of the this, a proper coordination and supervision initiative is data network and the implementation of future applica- required to define a common strategy aimed at optimiz- tions that guarantee the fulfillment of quality levels that ing the specification and subsequent installation of these are likely to be required by new markets (e.g. sensitive infrastructures, with a view to integrating with possible industrial loads and RES). future requirements as well as meeting the present day needs of the users. b.xii. Interconnections with Cambodia, China and Laos The definition of these basic structures for communica- tion and system control is fundamental to creating the The 220  kV interconnection with Cambodia was ini- right enabling platform for a transition towards smart grid tially installed and operated purely as a means of selling applications and functionality. energy to a load center. Volume 1: Technical Analysis 123 The current interconnection set-up is not experiencing Part of the northern Vietnamese electrical network is any operational problems and at present a telephone link connected to the Chinese grid through 110 kV and 220 kV is used between the operators of the two systems to over-head-lines, importing around 5 TWh/year. However, send instructions and exchange information. at the time of writing this report this link cannot be con- sidered an interconnection between the two countries The future development of the system and the possi- since this part of the Vietnamese network is separated ble introduction of hydro generation on the Cambodian from the rest of the national system when it is connected side (and a similar arrangement is expected with Laos to China. in the near future) will require very different operating conditions. In particular, it will be necessary to define In the near future the situation could change seeing that adequate operational procedures and a more efficient there are projects under evaluation for building new 500 interface between the operators of the provider and cli- kV lines permanently interconnecting the two countries. ent systems. In this case advanced applications and other manage- ment systems to assist the operators of the two sys- In order to address these issues it is proposed that tems are necessary. advanced applications and management systems be introduced to assist the operators of the two systems. Annex 3. FACTS Technology FACTS technology was originally developed to support In comparison with traditional mechanical devices, FACTS systems with long AC transmission lines but FACTS controllers, by virtue of having no moving parts, experience installations are nowadays more often used in meshed no wear and tear and thus require much less maintenance. grids to eliminate congestion and bottlenecks. In general, FACTS devices can be traditionally classified Depending on the type and rating of the selected device according to the manner in which they are connected and on the specific voltage level and local network con- [32], that is as: ditions, the transmission capacity enhancement achiev- able by installing a FACTS element could be as high as a. Shunt controllers. Among shunt controllers the 40-50% [31]. main devices are the Static VAR Compensator FIGURE 77: SVC AND STATCOM CONFIGURATION Source: Friends Of the SuperGrid, 2012, (21) (SVC) and the Static Synchronous Compensator FIGURE 78: TCSC CONFIGURATION (STATCOM). Typical schematics for these sys- tems are provided in Figure 77. b. Series controllers. The series controller category includes devices such as the Thyristor Controlled Series Capacitor (TCSC) and a typical schematic for this system is shown in Figure 78. Combined controllers. The combination of Series and Shunt Compensators systems typically used to further increase the manageability of AC transmission systems are known as Unified Power Flow Controller (UPFC). FACTS devices can also be classified according to the power electronics technology used for the converters, as Source: Friends Of the SuperGrid, 2012, (21) follows: 124 Volume 1: Technical Analysis 125 a. Thyristor-based controllers. This category includes Considering the state of development and the real appli- those devices based on thyristors, namely the cation examples available today, the notes below refer SVC and the TCSC; only to the most commonly used major systems such as SVC, TCSC and STATCOM. b. Voltage source-based controllers. These devices are based on more advanced technology like Gate Turn- The development of the VSC converter has led to the Off (GTO) thyristors, Integrated Gate Commutated development of VSC HVDC applications embedded in AC Thyristors (IGCT) and Insulated Gate Bipolar Transis- systems, as discussed in detail in the previous section tors (IGBT). This group includes the STATCOM; ‘D.4.4’, instead of the use of UPFC or similar systems. c. The voltage source-based devices are the most This is because a cost/benefit analysis usually favors the advanced FACTS systems and offer a smoother adoption of a HVDC systems rather than the implemen- and faster control of active and/or reactive power tation of a complex FACTS system. flow and/or nodal voltage amplitude indepen- dently of the loading/current conditions. Nevertheless, the exploitation of the main features and capabilities of the aforementioned basic FACTS devices A general identification of the different types of FACTS such as SVC, TCSC, STATCOM, is wide spread as they developed for applications within a transmission network have been in service in transmission networks for several is given in the table of Figure 79. decades especially to address network congestion instead of the traditional solu- FIGURE 79: FACTS DEVICES tion of increasing the transmission capacity by building new lines and substations [33]. In this sense, FACTS are an effective way to optimize the existing transmis- sion structures and to free paths that are occupied by undesired power flows (i.e. active loop flows, reactive power flow) in order to make better use of the existing lines, up to the maximum possible oper- ating conditions thus reducing losses and preventing possible system congestion. Figure 80 outlines the expected typi- cal impact of a SVC system in terms of increasing the transmission capacity and stabilization of the system voltage. Source: Authors FIGURE 80: ENHANCEMENT OF THE SYSTEM STABILITY BY MEANS OF A SVC Source: ABB, 2013, (8) 126 Smart Grid to Enhance Power Transmission in Vietnam Figure 81 shows a more general view of the variety of possible applications FIGURE 81: FACTS APPLICATIONS FOR POWER QUALITY AND SYSTEM STABILITY for the range of FACTS devices relative to the various problems that might be experienced in a transmission network. The matrix shows a broader picture of the possible application of power electronic devices and includes issues with power quality in distribution networks and for consumers where FACTS devices have been successfully deployed as well as for HVDC applica- tions as discussed in section ‘F.8’. Typical examples of possible applica- tions are increasing the transmission capacity within a section of the existing power grid or setting-up a new connec- tion to the main grid for large remote Source: IEA, 2013, (20) generation units and include new inter- connections with TSOs of neighboring countries. This approach always requires a detailed analysis to con- sider all the possible aspects and it is necessary to set- In this case an advanced solution, based on the introduc- up suitable technological, economic and environmental tion of FACTS applications, is often favored over conven- criteria to be applied in order to verify that the FACTS tional alternatives. solution is the best of all possible options examined dur- ing the transmission expansion planning process. References [1] DECISION No° 1208/2011/QD-TTg , “APPROVAL [15] U.S. Department of ENERGY, “Case Study— OF THE NATIONAL MASTER PLAN FOR POWER NASPI—Synchrophasor Technologies for a Better DEVELOPMENT FOR THE 2011–2020 PERIOD . Grid - August 2011” . WITH THE VISION TO 2030” [16] U.S. Department of Energy, “Dynamic Line Rating [2] NPT Smart Grid Roadmap. , 2014. Systems for Transmission Lines” [3] ENTSO-E, “Ten-Year Network Development Plan [17] A. T. Holen, L. Warland, “Estimation of Distance 2014” , 2014. to Voltage Collapse: Testing an Algorithm Based on Local Measurements” , 14th PSCC Conference, [4] D. Cirio, A. Danelli, M. Pozzi, S. Cecere, G. Sevilla, June 2002. Giannuzzi, M. Sforna, “Wide Area Monitoring and Control System: the Italian research and develop- [18] M. Begovic, B. Milosevic, D. Novosel, “A Novel ment”, CIGRE Session 2006, paper C2-208, Paris, , 35th Method for Voltage Instability Protection” 2006. Hawaii International Conference on System Sci- ences, 2002. [5] A. Danelli, G. Giannuzzi, M. Pozzi, R. Salvati, M. Sal- vetti, M. Sforna, “A DSA-integrated shedding sys- [19] M. Bernardi, C. Giorgi, V. Biscaglia, “Medium volt- tem for corrective emergency control” , 2005 Power age line faults correlation with lightning events Systems Computation Conference, August 22-26, recorded with the Italian LLP system CESI-SIRF” , 2005, Liege, Belgium. Proc. 24th International Conference on Light- ning Protection, Birmingham-UK, 1998, vol.1, pp. [6] C. Candia, D. Cirio, G. Giannuzzi, M. Pozzi, M. 187-192. Sforna: “PMU Location and Parameter Identifica- tion Techniques for the Italian Wide-Area Measure- [20] C.A. Nucci, M. Paolone, M. Bernardi, “Use of Light- ment System” , International World Energy System ning Location Systems Data in Integrated Systems Conference, Turin, Italy, 2006. , Proc. IEEE T&D Con- for Power Quality Monitoring” ference, Yokohama (Japan), October 2002, vol.1, [7] D. S. Piccagli, M. Barbieri, M. R. Pozzi, G. Giannuzzi, pp. 552-556. R. Zaottini, F. Bassi, ”Recent Advances In WAMS Data Processing: Off-Line And On-Line Applica- [21] CEIT IPCO 2014, “Voltage stability improvement tions For Stability Monitoring And Dynamic Load- using Re-locatable Static Var Compensator in Alge- ing”, CIGRÉ Belgium Conference 2014. rian Southeastern region”. [8] UCTE, Final Report-System Disturbance on 4 [22] “AC Grid with Embedded VSC-HVDC for Secure November 2006. , and Efficient Power Delivery - IEEE Energy 2030” 17-18 November, 2008 Atlanta, USA. [9] UK electricity transmission, National Grid Elec- tricity, “Ten Year Statement-2014” . http://www2. [23] “500 kV VSC Transmission System for lines and n a t i o n a l g r i d . c o m / U K / I n d u s t r y- i n fo r m a t i o n / , CIGRE—2012 San Francisco Colloquium cables” Future-of-Energy/Electricity-Ten-Year-Statement/ CIGRE report 492. [10] CIGRE JWG 14/37/38/39-24, “FACTS technology [24] “Voltage Source Converter (VSC) HVDC for Power for open access” , August 2000. Transmission – Economic Aspects and Comparison , CIGRE report with other AC and DC Technologies” [11] ABB Review, “Relocatable static var compensa- 492, April 2012. , May 1997 tors” . [25] “Assessment and Analysis of the State-Of-the-Art [12] CIGRÉ, “Relocatable GTO-Based Static Var Com- Electric Transmission Systems with Specific Focus , 1998. pensator for National Grid Substations” on High-Voltage Direct Current (HVDC), Underground [13] http://www.nerc.com/ or Other New or Developing Technologies” , Alberta Department of Energy, December 23, 2009. [14] NASPI updated and technology roadmap, 2011. 127 128 Smart Grid to Enhance Power Transmission in Vietnam [26] “Comparison of AC and DC technologies for long- [30] Ngo Son Hai, Nguyen The Huu, “Operational Prob- distance interconnections—RESEARCH, METH- , lems and Challenges in Power System of Vietnam” ODOLOGIES AND TECHNOLOGIES FOR THE National Load Dispatch Centre of Vietnam. EFFECTIVE DEVELOPMENT OF PAN-EUROPEAN [31] “Roadmap to the Supergrid Technologies - Final KEY GRID INFRASTRUCTURES TO SUPPORT THE , FOSG WG 2, March 2012. Report” ACHIEVEMENT OF A RELIABLE, COMPETITIVE AND SUSTAINABLE ELECTRICITY SUPPLY” , Revi- [32] “Improving network controllability by Flexible Alter- sion: 2010-03. nating Current Transmission System (FACTS) and by High Voltage Direct Current (HVDC) transmission [27] Per AGRELL, Peter BOGETOFT, “International Bench- systems—RESEARCH, METHODOLOGIES AND marking of Electricity Transmission System Opera- TECHNOLOGIES FOR THE EFFECTIVE DEVEL - , e3GRID PROJECT—FINAL REPORT, 2009. tors” OPMENT OF PAN-EUROPEAN KEY GRID INFRA- [28] Paul L. Joskow, “INDEPENDENT SYSTEM OPERA- STRUCTURES TO SUPPORT THE ACHIEVEMENT TORS (VI + Access Rules vs. ISO vs. ITSO)” , Sep- OF A RELIABLE, COMPETITIVE AND SUSTAINABLE tember 28, 2007 . ELECTRICITY SUPPLY” , Revision: 2010-03. [29] Annex Power, “MARKET POTENTIAL FOR SMART [33] IEA—International Smart Grid Action network, GRID TECHNOLOGY IN THAILAND AND VIET- “Smarter And Stronger power Transmission: review NAM”, January 2013. of Feasible Technologies for enhanced capacity and , Discussion Paper, August 2013. flexibility” MAPS, FIGURES, AND TABLES SOURCES (12) www.naspi.org (1) G. Giannuzzi, C. Sabelli, R. Salvati, R. Zaottini, C. (13) https://www.smartgrid.gov/files/synchrophasor_ Candia, M. Cignatta, A. Danelli, M. Pozzi, ”Voltage project_status_110114-3.pdf and Angle Stability Monitoring: Possible Approaches (14) U.S. Department of Energy, “Dynamic Line Rating in the Framework of a Wide Area Measurement , 2014. Systems for Transmission Lines” System (WAMS)” , Cigrè, Paris, 2008. (15) http://www.energy.ca.gov/maps/infrastructure/3P_ (2) WG C4.6.01–TF: Wide Area Monitoring and Control Enlg.pdf for Transmission Capability Enhancement, 2007. (16) http://www.ewh.ieee.org/r6/san_francisco/pes/pes_ (3) D. S. Piccagli, M. Barbieri, M. R. Pozzi, G. Giannuzzi, pdf/TransBayCable2014.pdf R. Zaottini, F. Bassi, ”Recent Advances In WAMS Data Processing: Off-Line And On-Line Applications (17) SIEMENS, Commercial documentation, 2013. For Stability Monitoring And Dynamic Loading” , (18) NPT–World Bank presentation, “Smart Grid Evolution CIGRÉ Belgium Conference 2014. , 2013 for Vietnam Power Transmission Network” (4) UCTE, Final Report-System Disturbance on 4 (19) Technical University Dortmund, “Research, November 2006. methodoLogIes and technologies for the (5) ENTSO-E, “Ten-Year Network Development Plan effective development of pan-European key GRID 2014” , 2014. infrastructures to support the achievement of a reliable, competitive and sustainable electricity (6) UK electricity transmission, National Grid supply” , 2010. Electricity, “Ten Year Statement-2014” . http:// www2.nationalgrid.com/UK/Industry-information/ (20) IEA—International Smart Grid Action network, Future-of-Energy/Electricity-Ten-Year-Statement/ “Smarter And Stronger power Transmission: review of Feasible Technologies for enhanced capacity and (7) CIGRE JWG 14/37/38/39-24, “FACTS TECHNOLOGY , Discussion Paper, August 2013. flexibility” for OPEN ACCESS”, August 2000. (21) Friends Of the SuperGrid, “Roadmap to the (8) ABB, Commercial documentation, 2011. , Final Report, 2012. Supergrid Technologies” (9) ALSTOM, Commercial documentation, 2013. (22) Albert Energy, “ Assessment and Analysis of the (10) NASPI updated and technology roadmap, 2011. State-Of-the-Art Electric Transmission Systems with Specific Focus on High-Voltage Direct Current (11) Cigrè, “Wide Area Monitoring Protection and Control (HVDC), Underground or Other New or Developing Deployment Roadmaps” , 2013. Technologies”, 2009. Volume 1: Technical Analysis 129 (23) Donal Skelly, GE Digital Energy, “The Transition ENDNOTES to Next-Generation Online DGA Monitoring 1. Operational Expenses , Technologies Utilizing Photo-Acoustic Spectroscopy” General Electric Company, 2013. 2. Energy Not Served (24) Per AGRELL, Peter BOGETOFT, “International 3. Phase Measurement Units Benchmarking of Electricity Transmission System 4. Internal Rate of Return , e3GRID PROJECT—FINAL REPORT, Operators” 2009. (25) Annex Power, “MARKET POTENTIAL FOR SMART GRID TECHNOLOGY IN THAILAND AND VIETNAM”, January 2013. 2 Volume 2: Cost-Benefit Analysis 131 Table of Contents A. Acronym List.......................................................................................................................137 B. Summary of Cost-Benefit Analysis....................................................................................139 C. Introduction.........................................................................................................................149 C.1 General Overview.........................................................................................................................................149 C.2 Document Structure.....................................................................................................................................150 D. Cost-Benefit Analysis Structure and Base Assumptions.................................................151 D.1 Key Points Summary....................................................................................................................................151 D.2 Description of Assessed Benefits and Costs..............................................................................................152 D.3 Assumptions.................................................................................................................................................153 D.3.1 Discount rate.......................................................................................................................................153 D.3.2 Timeline and pace of implementation ................................................................................................153 D.3.3 Peak demand.......................................................................................................................................153 D.3.4 Consumption.......................................................................................................................................153 D.3.5 Number of customers .........................................................................................................................153 D.3.6 Power capacity ....................................................................................................................................153 D.3.7 Transmission network sizing ...............................................................................................................154 D.3.8 Transmission network performances...................................................................................................154 E. Identify and Quantify Benefits...........................................................................................155 E.1 Key points summary....................................................................................................................................155 E.2 Mapping Assets to Functionalities..............................................................................................................155 E.3 Mapping Functionalities to Benefits...........................................................................................................158 E.4 Benefits monetization..................................................................................................................................161 E.4.1 Monetization of Energy Not Served reduction....................................................................................161 E.4.2 Substation Automation System (SAS)..................................................................................................162 E.4.3 Wide Area Monitoring System (WAMS)..............................................................................................163 E.4.4 Lightning Location System (LLS).........................................................................................................164 E.4.5 Static Var Compensator (SVC)..............................................................................................................164 E.4.6 High Voltage Direct Current (HVDC) technology..................................................................................165 E.4.7 Fault Locator System (FLS)..................................................................................................................167 E.4.8 On-line Dissolved Gas-in-oil Analysis (DGA).........................................................................................167 E.4.9 Dynamic Thermal Circuit Rating (DTCR)..............................................................................................168 E.4.10 Geographic Information Systems (GIS)................................................................................................168 E.4.11 Power quality monitoring and Metering Data Acquisition Systems.....................................................169 E.5 Assumptions about System Level Benefits................................................................................................169 E.5.1 Optimized energy generation mix........................................................................................................170 E.5.2 Increased fuel availability.....................................................................................................................171 E.5.3 Reduced GHG emissions.....................................................................................................................171 E.6 Integration of Renewable energy generation............................................................................................173 E.7 Assumptions on blackout prevention.........................................................................................................173 E.8 Summary of the Benefits.............................................................................................................................175 133 134 Smart Grid to Enhance Power Transmission in Vietnam F. Identify and Quantify Costs...............................................................................................176 F.1 Key Points Summary ...................................................................................................................................176 F.2 Substation Automation System (SAS).......................................................................................................176 F.3 Wide Area Monitoring System (WAMS).....................................................................................................177 F.4 Lightning Location System (LLS)................................................................................................................178 F.5 Static Var Compensator (SVC).....................................................................................................................178 F.6 High Voltage Direct Current (HVDC) technology .......................................................................................180 F.7 Fault Locator System (FLS)..........................................................................................................................180 F.8 On-line Dissolved Gas-in-oil Analysis (DGA).............................................................................................181 F.9 Dynamic Thermal Circuit Rating (DTCR).....................................................................................................182 F.10 Geographic Information Systems (GIS).....................................................................................................182 F.11 Power Quality monitoring and Metering Data Acquisition Systems.......................................................183 G. Compare Costs and Benefits..............................................................................................184 G.1 Key Points Summary....................................................................................................................................184 G.2 Substation Automation System (SAS).......................................................................................................185 G.3 Wide Area Monitoring System (WAMS).....................................................................................................185 G.4 Lightning Location System (LLS)................................................................................................................188 G.5 Static Var Compensator (SVC).....................................................................................................................189 G.6 High Voltage Direct Current (HVDC) technology........................................................................................190 G.7 Fault Locator System (FLS)..........................................................................................................................191 G.8 On-line Dissolved Gas-in-oil Analysis (DGA).............................................................................................192 G.9 Dynamic Thermal Circuit Rating (DTCR).....................................................................................................193 G.10 Geographic Information Systems (GIS)....................................................................................................194 G.11 Power quality monitoring and Metering Data Acquisition Systems......................................................195 H. Sensitivity Analysis.............................................................................................................196 H.1 Key Points Summary....................................................................................................................................196 H.2 Energy Not Served value sensitivity analysis............................................................................................196 H.3 Substation Automation System (SAS).......................................................................................................198 H.4 Wide Area Monitoring System (WAMS).....................................................................................................198 H.5 Lightning Location System (LLS)................................................................................................................198 H.6 Static Var Compensator (SVC).....................................................................................................................198 H.7 High Voltage Direct Current (HVDC) technology ...................................................................................... 200 H.8 Fault Locator System (FLS)......................................................................................................................... 200 H.9 On-line Dissolved Gas-in-oil Analysis (DGA)............................................................................................ 200 H.10 Dynamic Thermal Circuit Rating (DTCR)...................................................................................................202 H.11 Geographic Information Systems (GIS)....................................................................................................202 H.12 Power quality monitoring and Metering Data Acquisition Systems......................................................202 I. Risk Analysis.......................................................................................................................205 I.1 Key Points Summary....................................................................................................................................205 I.2 Definition of risks categories, scale and likelihood...................................................................................205 I.3 Risk assessment of Smart Grid initiatives..................................................................................................207 I.3.1 Substation Automation System (SAS)..................................................................................................207 I.3.2 Wide Area Monitoring System (WAMS)..............................................................................................209 I.3.3 Lightning Location System (LLS).........................................................................................................209 I.3.4 Static Var Compensator (SVC)..............................................................................................................209 I.3.5 High Voltage Direct Current (HVDC) technology..................................................................................210 I.3.6 Fault Locator System (FLS)..................................................................................................................210 I.3.7 On-line Dissolved Gas-in-oil Analysis (DGA).........................................................................................210 I.3.8 Dynamic Thermal Circuit Rating (DTCR)..............................................................................................210 I.3.9 Geographic Information Systems (GIS)................................................................................................ 211 I.3.10 Power quality monitoring and Metering Data Acquisition Systems..................................................... 211 Volume 2: Cost-Benefit Analysis 135 I.4 Risk Map........................................................................................................................................................ 211 I.5 Risk mitigation actions.................................................................................................................................212 J. Final Prioritization...............................................................................................................213 J.1 Key Points Summary....................................................................................................................................213 J.2 Smart Grid initiatives time positioning......................................................................................................213 References.................................................................................................................................218 Maps, Figures and Tables Sources.................................................................................................................219 Endnotes........................................................................................................................................................219 A. Acronym List CAPEX Capital Expenditures LSA Line Surge Arrester CBA Cost Benefit Analysis MBTU M (a thousand) British Thermal Unit DGA Dissolved Gas-in-oil Analysis NARUC National Association of Regulatory Utility Commissioners DLR Dynamic Line Rating NLDC National Load Dispatch Centre DTCR Dynamic Thermal Circuit Rating NPT National Power Transmission Corporation ENS Energy Not Served NPV Net Present Value ERAV Electricity Regulatory Authority of Vietnam OPEX Operating Expenditures EVN Electricity of Viet Nam PMU Phase Measurement Unit FLS Fault Locator System PQ Power Quality GHG Green House Gas SAS Substation Automation System GIS Geographic Information System SAIDI System Average Interruption Duration HVDC High Voltage Direct Current Index IED Intelligent Electronic Device SAIFI System Average Interruption Frequency JRC Joint Research Centre Index KPI Key Performance Indicator SVC Static Var Compensator LLS Lightning Location System VoLL Value of Lost Load LNG Liquefied Natural Gas WAMS Wide Area Monitoring System 137 B. Summary of Cost-Benefit Analysis This document presents Cost Benefit Analyses of Smart The Cost-Benefit analyses performed in this report aim to Grid Applications. The Project started by designing the identify the costs and benefits of each proposed Smart strategy and gathering information in order to perform Grid initiative and evaluate their economic parameters in an adjusted Roadmap of a Smart Grid implementation for order to understand the real added value of each initiative. Vietnam. The first step in the project was to identify the possible Smart Grid Applications and Smart Grid devices In order to have a complete understanding of the pro- that may help to resolve the problems identified by the posed Smart Grid initiatives from both the technical and Vietnamese power authorities. The Task-1 report defined economic points of view, it is fundamental to perform a a common shared vision of applications and equipment Cost-Benefits Analysis (CBA). for the Smart Grid development in Vietnam starting with the current operating model and the predicted status of In order define a starting point for this analysis it is crucial the electricity sector. to understand the baseline scenario and the predicted growth rate of the Vietnamese transmission system. The Smart Grid initiatives were tailored to fit the specific Towards this end some base assumptions have been needs of Vietnam, taking account of not only the best made and shared with the Vietnamese stakeholders. international practices and experiences but also the cur- These are and summarized in Table 17 . rent operational problems and the current status of the Smart Grid initiative in Vietnam. It is essential to identify the costs of each Smart Grid solu- tion and to evaluate their economic and technical benefits in The technical analysis performed in Task-1 identified the order to understand the real added value of each initiative. Smart Grid initiatives that are viable in Vietnam. These solutions have been provisionally prioritized after a tech- Starting from some basic assumptions regarding the type nology-focused investigation. of benefits (direct and system level), costs (Capital Expen- ditures—CAPEX—and Operating Expenditures—OPEX) TABLE 17: SMART GRIDS BUSINESS CASE—SUMMARY OF BASE ASSUMPTIONS Topic Major assumptions Peak demand • Baseline data (2015) in GW = 22.5 (source: NLDC). • The predicted average peak load growth rate over a 15 year timeframe is +9%/year (source: NLDC). Consumption • Baseline data (2015) in TWh = 161 (source: NLDC). • Predicted growth rate over a 15 year timeframe is 7-8%/year (source: NLDC). Number of • Baseline data (2012) equal to 19.781 million, with 18.564 million residential customers, 391,493 customers commercial customers, 53,296 Agricultural and 518,610 industrial customers and 253,919 others. • Predicted growth rate over a 15 year timeframe is 8% Power capacity • Baseline data (2015) of installed capacity in GW = 33 GW (source: NPT). • 2030 installed capacity = 146.8 GW (source: NPT) of which: o Hydropower accounts for 11.8%; o Energy storage hydropower for 3.9%; o Coal thermal power for 51.6%; o Gas fired power for 11.8% (of which LNG 4.1%); o Power using renewable energy for 9.4%; o Nuclear power for 6.6%; o Imported power for 4.9%. (Continued next page) 139 140 Smart Grid to Enhance Power Transmission in Vietnam TABLE 17 (CONTINUED) Topic Major assumptions Transmission • Transmission lines (source: NPT-NLDC): network sizing o 500kV = 6,756 km (2014), ~+16%/year growth rate (average in period 2009 – 2014) o 220kV = 12,513 km (2014), ~+6.6%/year growth rate (average in period 2009 – 2014) • Transmission substations: o 164 (2015), ~+7% new substations/year • Transformers (source: NPT-NLDC): o 500kV = 21,900 MVA (2014), ~ +32% per year (average in period 2009 – 2014) o 220kV = 31,351 MVA (2014), ~+15% per year (average in period 2009 – 2014) Transmission • SAIFI: 27.975 in 2013 (source: EVN estimation); network • SAIDI: 4,461 minutes in 2013 (source: EVN estimation); performances • Network losses equal to 2.49%, whose technical assumed 70% and non-technical 30% (source: NPT); • The total cost for system operation is $400,000,000 per year (source: NPT, 2014). Source: Authors the CBA evaluates the Key Performances Indicators this issue is quite limited and a detailed study would be (KPIs) of each Smart Grid application in the context of the necessary to obtain the exact value of the likely Direct Vietnamese transmission system. In particular, the CBA Transmission OPEX reduction for Vietnam. However, is based on the steps recommended by the Joint Research exhaustive analysis of this aspect is outside the scope Centre Institute for Energy and Transport (JRC). Based on of this work, a conservative estimation of the financial the mapping of initiatives onto functionalities and of func- value of the benefits has been made for the purposes tionalities onto benefits for each Smart Grid solution it has of performing the CBA. The operating cost reduction been possible to quantify these direct benefits: potentially achievable from a Smart Grid development has been assumed to be 8%. This is based on the con- a. Direct Transmission OPEX reduction; sultant’s extensive experience in this field garnered from similar international projects, and takes account of the b. Reduction of energy not served; current status of the variables likely to affect this estima- c. Reduction of power losses; tion that are present in the Vietnamese scenario. The indi- vidual Smart Grid initiatives contribute in different ways d. Improved system reliability through reduced fre- to achieving this level of cost reduction. quency and duration of system faults; e. Amount of CAPEX investment in transmission In order to estimate the amount of ENS reduction for system saved; some of the initiatives it has been assumed that a cer- tain type of fault event on the transmission network (e.g. f. Deferred investment in Capacity enhancements. a voltage collapse) causes a brownout each year corre- In order to express these benefits in financial terms sponding to a certain percentage of the peak load (e.g. some assumptions have been made for each Smart 10%) and such an event lasts for a number of minutes Grid initiative. The most challenging ones are related to (e.g. 30 minutes). A review of the available literature “Direct Transmission OPEX reduction” and to “expected on the subject has failed to shed any light on the link Energy Not Served (ENS) reduction” due to a fault event between the cost savings from a Smart Grid based ENS prevented or avoided. reduction and the commensurate level of OPEX reduc- tion. Therefore, once again, the cost benefit analyses The savings that can be achieved through optimization presented in this document relies on the consultant’s of operating costs by using automation are assumed to experience of the knock on benefits of ENS reductions range between -5% and -10% based on international and offers a conservative estimate that, again, takes experiences (e.g. the Italian case). Such benefits can, of account of the prevailing situation discovered within the course, vary significantly as a function of specific network context of the Vietnamese power network. characteristics and architecture, productivity of resources involved in network operations and the levels of regu- The major assumptions regarding the direct benefits offered lar maintenance and service provided. The literature on by the Smart Grid applications are summarized in Table 18. Volume 2: Cost-Benefit Analysis 141 TABLE 18: SUMMARY OF BENEFITS MONETIZATION ASSUMPTIONS ON SMART GRID INITIATIVES Initiative Major assumptions regarding benefits • A SAS installation can contribute about 60% to the global reduction of the OPEX for the transmission system. SAS • An average value of ENS reduction per year, per substation equipped with SAS is about 100 MWh. • The cost of ENS is 3,000 $/MWh. • A WAMS installation can contribute about 10% to the global reduction of the OPEX for the transmission system. • The total number of voltage collapse events cause approximately 10% of brownouts of the peak load per year accounting for a total of 30 minutes. WAMS • The prevention capacity is directly proportional to the pace of installation. • All new substations brought on-line and 68 of the old ones will be equipped with PMUs. • WAMS functions that help prevent such events will be available after 3 years from the start of the project. • The brownout prevention capacity is increased by 20% if all substations are equipped with PMUs. • A Lightning Location System can contribute about 5% to the global reduction of the OPEX for the transmission system. Lightning • The phase-to-phase-to-ground faults caused by lightning account for 8% of the total number of faults caused by lightning. Location • These events cause about 2% brownout of the peak load per year accounting for a total of 30 minutes. System • This application will result in a 25% reduction of the number of phase-to-phase-to-ground faults caused by lightning. • The ability to prevent such events will be available 3 years after the start of the project. • SVC installation can contribute 10% to the global reduction of the OPEX for the transmission system. • The total number of voltage collapse events cause approximately10% of brownouts of the peak load per year SVC accounting for a total of 30 minutes. • This application will result in a 25% reduction of the number of voltage collapse events. • A HVDC link can contribute 5% to the global reduction of the OPEX for the transmission system.. • 500 kV and 2000 MW rated power for both AC and HVDC solution. • AC and HVDC lines are the same length. • The OPEX is calculated at 1.5% of the capital expenditure for both AC and HVDC lines. OPEX for converter stations is 3% of their CAPEX (source: manufacturers). • Annual energy losses are calculated according to the following formula: HVDC o L_year=8760 LF X L_Pmax; where: oo LF = 70% is the loss factor, corresponding to 6,132 equivalent hours; and o L_Pmax are the losses at rated power and depend on the type of the transmission (AC or HVDC) and the size of the conductors. • The financial value of energy losses is estimated to be 60 $/MWh per year. • The annual financial value of the reduction of power losses is based on the difference between the value of AC and HVDC energy losses per year. • These events account for about 10% brownout of the peak load per year amounting to a total of 30 minutes. FLS • The prevention capacity is directly proportional to the number of lines equipped with FLS devices. • This application will result in a 25% reduction of time lost because of faults. • Average cost of a transformer fault is approximately $9,000 per MVA and the fault probability is estimated to be about 0.6%. DGA • The installation of this device in transformers will prevent about 80% of faults. • Dynamic Thermal Circuit Rating can contribute 5% to the global reduction of the OPEX for the transmission system. Dynamic • It is proposed that four critical lines be equipped with DLR sensors. Thermal • These lines are 100km in length. Circuit Rating • The costs estimated for these four lines include the cost of the DLR solution (1 sensor every 10km) and of reconductoring. • A DLR sensor costs $32,000 while the reconductoring costs $200,000/km. • It is assumed that the GIS application will only be developed for the SAS initiative and it is expected to result GIS in a 10% reduction in the OPEX for the SAS project. • Power quality monitoring and Metering Data Acquisition Systems can contribute 5% to the global reduction Power quality of the OPEX for the transmission system.. monitoring and • The fault events caused by critical voltage dips account for about 1% brownout of the peak load per year Metering Data amounting to a total of 15 minutes. Acquisition • The prevention capacity is directly proportional to the number of lines equipped with PQ devices. Systems • Power Quality monitoring will result in a reduction of 20% of fault time losses. Source: Authors 142 Smart Grid to Enhance Power Transmission in Vietnam The analyses performed also consider the cumulative need for any additional infrastructure and improving over- benefits at a system level of multiple smart grid initia- all system operation. The contributions of the individual tives. The assessment and the financial benefits of each Smart Grid initiatives are described with an emphasis on Smart Grid application has been performed indepen- HVDC technology and Dynamic Thermal Circuit Rating dently and not compounded in the calculation of the both of which are particularly useful for integrating vari- economic indicators at a system level, thus deliberately able renewable energy generation sources. underestimating their overall benefit. The benefits of blackout prevention, entirely achievable In order to be conservative and not overstate the case with the deployment of Smart Grids, are also investi- for the Smart Grid applications, the cumulative financial gated. International experience of the highly damaging value of the system level benefits has not been included effects and high costs associated with blackouts were in the economic evaluation of each Smart Grid initiative. the main drivers behind the development of Smart Grids However, the estimated financial value of each applica- technologies in the USA, Europe and around the world. tion has been compounded to create an economic indi- The benefits derived from blackout prevention are con- cator for the Smart Grid roadmap in its entirety. Such an sidered for the Vietnamese context. incremental global evaluation highlights how the devel- opment of even a subset of Smart Grid solutions (as Further, a cost estimation has also been performed to required for Vietnam) will expedite the construction of a provide a complete understanding of the key economic “Smart” transmission network to enhance the reliability parameters associated with the proposed Smart Grid of the electrical system. solutions. The costs have been broken down in terms of capital expenditure for the design activities, systems and The support for the integration of renewable energy gen- installation (CAPEX) and the operating expenditures of eration enabled by a Smart grid development has also running, managing and administering the installed sys- been analyzed. International experience, in fact, demon- tem (OPEX). The nominal and discounted values of such strates that Smart Grid solutions can facilitate the inte- costs have been amortized over a period of15 year and gration of Renewable Energy Sources whilst limiting the are summarized in Table 19. TABLE 19: SUMMARY OF COSTS OF SMART GRID INITIATIVES Initiative Nominal Costs Discounted Costs Scale of operation • CAPEX: $226,200,000 • CAPEX: $147,903,537 • 18 retrofitted substations. SAS • OPEX: $25,205,250 • OPEX: $10,854,340 • 150 new SAS. • CAPEX: $1,792,000 • CAPEX: $1,268,311 • 224 PMU installed at 500 kV and 220 kV voltage WAMS • OPEX: $214,840 • OPEX: $96,615 level. Lightning Location • CAPEX: $1,668,000 • CAPEX: $1,431,404 • 20 detectors monitoring lightning activity across System • OPEX: $899,000 • OPEX: $443,395 the country. • CAPEX: $31,500,000 • CAPEX: $24,962,690 • 900 Mvar SVCs installed in the most affected SVC • OPEX: $1,255,500 • OPEX: $588,058 areas of Vietnam. • CAPEX: ($16,800,000) • CAPEX: ($13,313,434) • 2,000 MW interconnection, 800 km length, HVDC • OPEX: $118,098,000 • OPEX: $55,315,436 using DC instead of AC technology. • CAPEX: $8,400,000 • CAPEX: $7,289,256 • 140 Fault locators. FLS • OPEX: Negligible • OPEX: Negligible • CAPEX: $77,592,000 • CAPEX: $41,696,690 • 732 transformers equipped, (includes current DGA • OPEX: $3,343,245 • OPEX: $1,364,572 and new). Dynamic Thermal • CAPEX: $1,280,000 • CAPEX: $1,110,743 • 40 sensors monitoring 400 km lines. Circuit Rating • OPEX: $371 200 • OPEX: $183,079 • CAPEX: $175,000 • CAPEX: $159,090 • Geographic information of power system GIS • OPEX: $262,500 • OPEX: $133,106 components throughout Vietnam. Power quality monitoring • CAPEX: $301,500 • CAPEX: $241,648 • 105 power quality measurement devices at 500 and Metering Data • OPEX: $97,214 • OPEX: $45,962 kV and 220 kV voltage level. Acquisition Systems Source: Authors Volume 2: Cost-Benefit Analysis 143 It is worth noting that in all but two cases the cost evalua- b. EIRR: the Economic Internal Rate of Return on an tion considers the full investment in a project. The excep- investment or project is the “annualized effective tions are LLS and HVDC where the calculation formula compounded return rate” (or rate of return) that was slightly different. makes the Net Present Value of all cash flows (both positive and negative) of a particular invest- The cost calculation variation for the LLS installation is ment equal to zero; because it is intertwined with the installation of the Trans- c. B/C ratio: the Benefits-Costs ratio summarizes mission Surge Line Arresters (TLSA). The cost of buying the overall value for money of a project and it is and installing TLSAs has not been factored into this analy- calculated as the ratio of the discounted present sis because it has been assumed that the NPT has to values of benefits and the discounted present val- install these devices independently of the installation of ues of costs; a Lightning Location System. Consequently for the LLS benefit evaluation in term of “Reduction of energy not d. Switching value: This is the value assumed of served” , the incremental fault reduction achievable with a an estimated benefit so as to equal zero NPV. The TLSA installation driven by a LLS is considered. assumption is chosen specifically for each Smart Grid initiative considering both the uncertainty of Table 19 shows that CAPEX for HVDC is negative because its estimation and the impact on the economic an incremental cost benefit-analysis has been performed benefits of the project. It is important to underline in this particular case. It is not possible to do a full cost that the Transmission OPEX reduction benefit, if benefit analysis because the benefit derived from the present, is considered equal to zero in the break- installation of a new line is something to be determined even calculation (conservative approach). on a case-by-case basis and cannot be generalized. But since the benefit of the new line, in terms of optimization Table 20 summarizes the synthetic values of the eco- of energy mix, is independent from the technology used nomic benefits of each Smart Grid initiative. (AC or DC), an incremental cost benefit analysis is really useful to understand the impact of the adoption of a DC It cannot be stressed enough that these values and line instead of an AC one. This also highlights the further indicators are very conservative, given the assumptions benefits that derive from using DC technology instead of made and most importantly, given that the system level the traditional AC. In either case it is possible to give the benefits discounted to 2015 derived from the optimized total CAPEX of the HVAC in comparison with the alterna- energy mix and increased fuel availability ($305,000,000), tive HVDC interconnection. In the calculation performed reduced GHG emission ($128,000,000) as well as for an over-head line of 800 kilometers (2 GW) the esti- the benefits accrued from major blackout prevention mated costs are: ($275,000,000) were not internalized in the economic indicators (NPV, EIRR and B/C ration). Thus, despite this a. HVAC: $692,800,000; deliberate underestimation, the indicators make a com- pelling and unambiguous case for the financial and tech- b. HVDC: $676,000,000. nical benefits of Smart Grid technology in general and of these specific applications in particular. This means that the HVDC link offers a CAPEX saving of $16,800,000 or 2.42% of the cost of the HVAC link. Following the cost benefit analysis a sensitivity analysis was also performed. The purpose was to measure the Therefore, the construction of a new HVDC line is not impact of the changes to the project variables of the a smart initiative itself, but the real smart aspect is the baseline scenario. choice of the HVDC technology for building already planned lines with certain characteristics instead of tradi- The variables assumed for the assessment vary for each tional AC technology. specific application. For this reason each Smart Grid initiative has been separately analyzed in order to find In order to evaluate the economic benefits of each Smart the variables that are characterized by a high degree of Grid initiative four parameters have been chosen. These uncertainty and yet have a significant impact on the eco- synthetic values are : nomic evaluation. a. Total NPV: the Net Present Value represents the Table 21 summarizes the sensitivity analysis parameters discounted cash flows, i.e. the present value of of each Smart Grid initiative. future cash flows calculated up to the year 2030; 144 Smart Grid to Enhance Power Transmission in Vietnam TABLE 20: SUMMARY OF THE SYNTHETIC VALUES OF THE ECONOMIC BENEFITS OF SMART GRID INITIATIVES Initiative Results • Total NPV: $179,002,262 • EIRR: 41% SAS • B/C ratio: 2.13 • Switching value: Avoided ENS per SAS = 75.9 MWh/year (assumes Transmission OPEX reduction benefit equal to zero) • Total NPV: $22,951,362 • EIRR: 204% WAMS • B/C ratio: 17.82 • Switching value: Percentage of events prevented = 4.94% (assumes Transmission OPEX reduction benefit equal to zero) • Total NPV: $11,035,144 • EIRR: 164% Lightning Location • B/C ratio: 6.89 System • Switching value: Percentage of events prevented = 21.3% (assumes Transmission OPEX reduction benefit equal to zero) • Total NPV: $5,265,412 • EIRR: 14% SVC • B/C ratio: 1.21 • Switching value: Percentage of events prevented = 60.3% (assumes Transmission OPEX reduction benefit equal to zero) • Total NPV: $23,524,111 • EIRR: All positive cash flowsa HVDC • B/C ratio: 1.56 • Switching value: Line length = 773 km (assumes Transmission OPEX reduction benefit equal to zero) • Total NPV: $1,235,045 • EIRR: 13% FLS • B/C ratio: 1.17 • Switching value: % monitored lines with faults = 64.1% • Total NPV: $5,532,566 • EIRR: 12% DGA • B/C ratio: 1.13 • Switching value: Average cost of a transformer fault = $7907 • Total NPV: $44,132,102 • EIRR: All positive cash flows Dynamic Thermal • B/C ratio: 35.11 Circuit Rating • Switching value: Line reconductoring investment deferment = 0.18 years (assumes Transmission OPEX reduction benefit equal to zero) • Total NPV: $762,214 • EIRR: 48% GIS • B/C ratio: 3.61 • Switching value: % reduction of SAS O&M = 2.7% • Total NPV: $11,003,193 Power quality • EIRR: 797% monitoring and • B/C ratio: 39.26 Metering Data • Switching value: Percentage of events prevented = 10.0% (assumes Transmission OPEX reduction Acquisition Systems benefit equal to zero) Source: Authors Note: a. If the costs are already greater than the benefits in the first few years all the cash flows are positive and there is not a discount rate value, which determines a zero NPV. Volume 2: Cost-Benefit Analysis 145 TABLE 21: SUMMARY OF THE SENSITIVITY ANALYSIS PARAMETERS OF SMART GRID INITIATIVES Initiative Sensitivity analysis parameters • Energy Not Served value. SAS • Average value of ENS reduction per year for every substation equipped with SAS • Energy Not Served value. WAMS • Percentage of fault events prevented. • Energy Not Served value. Lightning Location System • Percentage of fault events prevented. • Energy Not Served value. SVC • Percentage of fault events prevented. • Power losses cost. HVDC • Line length. • Energy Not Served value. FLS • Reduction of Outage time duration. • Percentage of lines with faults monitored with the FLS. DGA • Average cost of a transformer fault. • Number of lines with deferred reconductoring. Dynamic Thermal Circuit Rating • Number of years of deferred investment. GIS • Operation and maintenance cost savings for SAS application. Power quality monitoring and • Energy Not Served value. Metering Data Acquisition Systems • Percentage of fault events prevented. Source: Authors A risk analysis was performed in order to gather all the across the 2D grid shows the relative risk whilst the key information for the final prioritization of the initiatives color of each Smart Grid application identifies the risks in and the refinement of the Smart Grid roadmap. terms of three categories: The parameters used to evaluate the risks are as follows: a. Green shows the “Time” category risk; b. Violet the “Stakeholders’ actions” category risk; a. Risk categories; c. Orange the “Investment uncertainty” category b. Risk impact; and risk. c. Risk likelihood. This analysis has highlighted the solutions that carry the Based on these parameters a risk assessment was car- greatest risk such as FLS and DGA for want of “Time” , ried out for all the Smart Grid initiatives by weighing the “Stakeholders’ actions” or “Investment uncertainty” . risk impact with its likelihood and thus measuring the overall threat imposed by implementing each solution. These risks cannot be fully eliminated but they can be mitigated by taking some appropriate actions. This comparison is graphically depicted on a two dimen- sional grid in Figure 82. The highest risk for each Smart However, despite these attendant risks the final prioriti- Grid initiative is positioned on a map where the abscissa zation of all the Smart Grid initiatives places them on a (x axis) represents the risk impact while the ordinate (y timeline, defines the best starting point for each and an axis) represents the risk likelihood. The color shading ideal elapsed time for their development. 146 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 82: RISK MAP Source: Authors This prioritization is a refinement of the original Vietnam- a. Geographic Information Systems positioned in ese Smart Grid roadmap and articulates a phased imple- the short term; mentation plan. This prioritization is based on: b. Dynamic Thermal Circuit Rating positioned in the short term; a. The technical reasons described in technical anal- ysis report; c. Lightning Location System positioned in the short term; b. The economic results of the Cost-Benefit Analy- sis; and d. Fault Locator System with recommended pre- liminary activities and their final completion in the c. The risks and related mitigating actions. short term; As stated in the technical analysis report, three different e. Static Var Compensator with some preliminary time horizons are considered for the development of the activities in the short term with the finalization initiatives: of the total installed capacity impinging on the beginning of the medium term; a. Short term—within the next 5 years; f. Wide Area Monitoring System starts in the short b. Medium term—within the next 10 years; and term with completion occurring in the medium term. The prioritization of the main lines to all c. Long term—within the next 15 years. areas are in the short term; The refined Smart Grid prioritization roadmap is as g. Substation Automation System, including remote follows: control centers building/upgrading, already Volume 2: Cost-Benefit Analysis 147 started and therefore in the short term by default The positioning within a fixed time frame creates a start- will be completed in the medium term; ing point for the initiatives, and it is very likely that the implementation process for some solutions will take h. Power quality monitoring system and Metering more than five years. For example, the full development Data Acquisition System both start in the short of SAS, already commenced and therefore considered term with the full rollout in the medium term; a short-term initiative, will conclude in about ten years. i. High Voltage Direct Current technology with the Equally, the full implementation of WAMS, the Power required preliminary studies and activities in the quality monitoring system and the Metering Data Acqui- short term and completion in the medium term; sition System, which are tied to the installation of new and substations, will also conclude the same ten year period. j. On-line-Dissolved Gas-in-oil Analysis, already Figure 83 shows the final time positioning of the Smart started, to be positioned in the short term and Grid initiatives. continued during the whole development of the roadmap. 148 FIGURE 83: FINAL TIME POSITIONING OF SMART GRID INITIATIVES Smart Grid to Enhance Power Transmission in Vietnam Source: Authors C. Introduction C.1 General Overview for identifying and assessing financial benefits as well as costs and for performing a sensitivity analysis of the The technical analysis report has identified a number of most critical variables. Smart Grid initiatives that are appropriate for Vietnam. These solutions have been prioritized after a technology- Based on the JRC approach [1] the CBA offers an eco- focused investigation but no evaluation about their costs nomic analysis divided into three phases. and economic benefits has yet been performed. The first phase consists of a definition of the bound- The aim of this document is to identify the costs and ary conditions (demand growth forecast, discount rate, benefits of each Smart Grid solution and to evaluate their local grid characteristics, etc.). The second phase uses a economic parameters in order to understand the real “seven step approach” as shown in Figure 84. added value of each initiative. The third phase the Cost and Benefits analysis refines The Cost-Benefit Analysis (CBA) is based the key steps the process by changing the critical parameters of each of the “Guidelines for conducting a cost-benefit analysis project in order to find the best and most balanced Smart of Smart Grid projects” suggested by the Joint Research Grid strategy. Towards this end, a sensitivity analysis of Centre Institute for Energy and Transport (JRC). This the major variables is performed in order to evaluate the methodology offers an effective way of creating a set of deviation of the analysis results. guidelines for tailoring assumptions to local conditions, FIGURE 84: COSTS & BENEFITS ANALYSIS STEPS Source: JRC, 2012, (1) 149 150 Smart Grid to Enhance Power Transmission in Vietnam This is followed by a risk analysis that weighs the risk functionalities with commensurate benefits as well as impact and related likelihood of its occurrence for all the quantifying each of these Smart Grid solution benefits. Smart Grid initiatives. Chapter ‘F’ addresses cost estimations for the develop- ment of each Smart Grid initiative. Finally, based on the information and results obtained from the CBA and the risk analysis, it is possible to define The third part, composed of chapters ‘G’ and ‘H’, final- the final prioritization of Smart Grid initiatives and a resul- izes the analysis by comparing the costs and benefits tant phased implementation plan. of each solution and evaluating different implementa- tion scenarios. Chapter ‘G’ compares costs and benefits (identified and quantified in the previous chapters) and C.2 Document Structure estimates some economic indicators for each Smart Grid initiative. Chapter ‘H’ performs some sensitivity analyses This report is structured in four main parts. that evaluate different implementation scenarios for the various Smart Grid solutions, in order to understand the The first part, comprised of chapter ‘D’, identifies the key best time horizon of their development and to determine elements necessary to perform the Cost-Benefit Analy- the best deployment strategy. sis. This chapter describes the structure of the cost and benefits analysis, identifies assessed benefits as well as The fourth part, composed of chapters ‘I’ and ‘J’, per- costs and then articulates the main assumptions made forms the risk analysis and exploits the intelligence gath- about the Vietnamese transmission system. ered from the preceding sections (together with the results of CBA) to carry out the final prioritization of the The second part, composed of chapters ‘E’ and ‘F’, aims Smart Grid initiatives. In particular, chapter ‘I’ identifies to identify and quantify the benefits and costs of each the risks related to each. Finally, chapter ‘J’ presents the Smart Grid solution. These two chapters articulate the refined prioritization of all the Smart Grid initiatives, posi- main assumptions and the basic reasons for setting up tions them on a timeline, suggests the best starting point the implementation scenarios of the various Smart Grid for the solutions and recommends a suitable elapsed initiatives. In particular chapter ‘E’ is focused on bene- time for their development. fits. It associates initiatives with functionalities and then D. Cost-Benefit Analysis Structure and Base Assumptions D.1 Key Points Summary The Business Case has assumed a green field starting point for each initiative despite the fact that some are The proposed Smart Grid solutions for NPT have been already in progress. modeled to assess their profitability in terms of costs and benefits. The present chapter aims to identify the key ele- To create a starting point for this analysis it is crucial ments necessary to perform the Cost-Benefit Analysis, to understand the baseline scenario and the expected which it does by defining the benefits (direct and sys- growth rate of the Vietnamese transmission system. This tem level) and costs (CAPEX and OPEX) that have to be chapter identifies some base assumptions shared with considered. and approved by the Vietnamese stakeholders1 and are shown in Table 22. The Business Case is based on a Discounted Cash Flow (DCF) method, with final results presented for a period of The Business Case Model compares the Net Pres- 15 years (2016-2030), assuming a discount rate of 10%. ent Value of the Smart Grid applications. The model TABLE 22: SMART GRIDS BUSINESS CASE—SUMMARY OF BASE ASSUMPTIONS Topic Major assumptions • Peak demand • Baseline data (2015) in GW: 22.5 (source: NLDC). • The average peak load growth rate over a 15 year timeframe is +9%/year (source: NLDC). • Consumption • Baseline data (2015) in TWh: 161 (source: NLDC). • Growth rate over a 15 year timeframe is 7-8%/year (source: NLDC). • Number of customers • Baseline data (2012) equal to 19.781 million, with 18.564 million residential customers, 391,493 commercial customers, 53,296 Agricultural, 518,610 industrial customers and 253,919 others. • Growth rate over a 15 year timeframe is 8%. • Power capacity • Baseline data (2015) of installed capacity in GW: 33 GW (source: NPT). • 2030 installed capacity: 146.8 GW (source: NPT) of which: oo Hydropower accounts for 11.8%; oo Energy storage hydropower for 3.9%; oo Coal thermal power for 51.6%; oo Gas fired power for 11.8% (of which LNG for 4.1%); oo Power using renewable energy for 9.4%; oo Nuclear power for 6.6%; oo Imported power for 4.9%. • Transmission network • Transmission lines (source: NPT-NLDC): sizing oo 500kV: 6,756 km (2014), ~+16%/year growth rate (average in period 2009 – 2014). oo 220kV: 12,513 km (2014), ~+6.6%/year growth rate (average in period 2009 – 2014). • Transmission substations: oo 164 (2015), ~+7% new substations/year. • Transformers (source: NPT-NLDC): oo 500kV: 21,900 MVA (2014), ~ +32% per year. (average in period 2009 – 2014). oo 220kV: 31,351 MVA (2014), ~+15% per year. .(average in period 2009 – 2014). • Transmission network • SAIFI: 27.975 in 2013 (source: EVN estimation). performances • SAIDI: 4,461 minutes in 2013 (source: EVN estimation). • Network losses equal to 2.49%, whose technical assumed 70% and non-technical 30% (source: NPT). • The total cost for system operation is $400,000,000 per year (source: NPT, 2014). Source: Authors 151 152 Smart Grid to Enhance Power Transmission in Vietnam can simulate a number of scenarios to reflect possible iii. Increased continuity of service. Improved changes in the speed of the roll-out, predicted savings/ reliability from automated responses to some benefits, estimated costs for key items (i.e. Smart Grid types of outages and faster identification and new technologies and devices). Some of the key informa- repair of those that do occur thus reducing the tion has been taken from the NPT local environment, whilst duration or scale of outages. others have been sourced from international references. b. System level benefits that can be generated for the whole electrical system and are based on the The specific Business Cases that are illustrated in detail development of alternative energies in particular in the following sections separately considers: distributed renewable sources enabled by some of the Smart Grid solutions. The benefits are: a. Benefits linked to the deployment of such tech- nologies associated with either reducing costs or i. Optimized energy generation mix and peak raising revenues and are divided into: reduction. Renewable energy sources will result in lower CAPEX and OPEX costs, as i. Direct, if connected to Smart Grid solutions there will be no need for new conventional fos- and directly realized by the operators respon- sil fuel power stations to cover peak demand. sible for such initiatives (under the current The need for conventional fossil fuel power market structure); plants is expected to decrease noticeably over ii. System level, if not supported directly by the next years due to further innovations and Smart Grid solutions but a cumulative func- technology maturity; tion of other Smart Grid applications and not ii. Increased fuel availability. Given that Viet- directly realized by the operators. nam has limited natural coal sources this b. Costs, in terms of capital (CAPEX) and operat- reduction in conventional fossil fuel power sta- ing expenditures (OPEX), needed respectively for tions will result in a reduction of coal imports the design, purchase, installation etc and to oper- and enable the sale of their own coal output at ate once installed and commissioned (the value international prices; of asset not yet depreciated is considered in the iii. Reduced GHG emissions. Again, the reduc- terminal value calculation). tion in conventional fossil fuel power sta- tions will result in lower emissions of GHG D.2 Description of Assessed Benefits (CO2). This reduction will mean that Vietnam and Costs will meet its own carbon footprint reduction targets and facilitate a positive trade in GHG The implementation of the transmission network Smart emission certificates to those nations unable Grid solutions offers a wide-range of benefits for the to reduce their carbon footprint to internation- whole electrical system. ally agreed levels. The Business Case verifies the sustainability of the Smart The following aspects have been considered in relation Grids solutions proposed for Vietnam and considers the to the cost of Smart Grid applications: benefits both direct and at system level: a. Transmission system CAPEX, includes: a. Direct benefits, which can be achieved by i. Procurement of transmission network equipment operators: for installation on the grid including transmission i. Reduced operating costs of T&D System. line sensors, HVDC terminals, SVC devices, and Reduction/optimization of resources involved phasor measurement technology for wide area in the manual operations and maintenance of monitoring; the electrical grid enabled by the implementa- ii. Cost of enterprise back-office systems and asso- tion of Smart Grid solutions; ciated hardware (including outage and transmis- ii. Improved quality of services and losses. sion management); and Reduction of technical losses on the electri- iii. Cost of supporting IT/Cyber Security and commu- cal networks due to automated control of grid nications infrastructure for transmission lines to voltage and power factor systems, optimiza- substations. tion of load dispatching and management; Volume 2: Cost-Benefit Analysis 153 b. Transmission system OPEX, including cost of a. rd = 6.5%. The yields on comparably rated bonds maintenance and operations of the above men- with maturity periods similar to the timescales of tioned automation systems and equipment. the investment has been adopted; b. re = rd + 5.3%. This uses the bond yield value D.3 Assumptions plus a risk premium of 5.3% as a means of esti- mating the cost of equity; The Business Case for Smart Grid solutions has been devel- c. = 33%. Debt-to-total capitalization ratio; oped based on specific assumptions about the expected growth and evolution of the electrical transmission system and (in a business as usual scenario) and on the benefits and costs as described in the previous section ‘D.2’. d. = 67%. Equity-to-total capitalization ratio. Such assumptions are based on public institutional The discount rate is estimated to be 10%. sources for Vietnam’s electrical system and, where unavailable, the consultant‘s direct project experiences D.3.2 Timeline and pace of implementation mindful of the knowledge and/or perception of the par- ticular requirements of the Vietnamese systems. A timeline of 15 years (2016-2030) has been proposed for the implementation of the identified Smart Grids solu- It is important to outline that all assumptions have been tions as per the Vietnamese roadmap. submitted to and approved by the Vietnamese stakehold- ers and decision makers in order to ensure consistency The implementation pace of the Smart Grid applications with local market characteristics and projects already is based on the particular characteristics and architecture. underway in the country. D.3.3 Peak demand The following assumptions are based on the current sta- tus of the electrical system and expected development in The anticipated peak load for 2015 is estimated at 22.5 GW. a business as usual scenario. The average peak load growth rate over a 15 year period The next section presents assumptions that refer to the is predicted to be ~+9%/year. characteristics of the Vietnamese transmission system. The specific identification and quantification of benefits D.3.4 Consumption regarding the proposed Smart Grid initiatives are detailed in chapter ‘E’. The same investigation about Smart Grid The anticipated electricity consumption in 2015 is esti- initiatives costs are carried out in chapter ‘F’. mated at 161 TWh. The average growth rate in electricity consumption over D.3.1 Discount rate a 15 year timeframe is predicted to be 7%–8%/year. At the outset it is important to assume a discount rate value in order to compare the Net Present Value of the D.3.5 Number of customers Smart Grids application components. The calculation below uses the assumed Discount rate and Weighted In 2012 there were 19.781 million customers of which Average Cost of Capital (WACC): 18.564 million were residential, 391,493 were commer- cial, 53,296 were agricultural and 518,610 industrial cus- tomers with 253,919 others. where: The growth rate in the number of customers over a 15 year period is predicted to be 8%. a. rd = cost of debt; b. re = cost of equity; D.3.6 Power capacity c. D = market value of debt; and The total installed power capacity for 2015 is estimated at about 33 GW while the installed capacity in 2030 has d. E = market value of equity. been predicted at about 146.8 GW. The combination of For Vietnam the following values have been assumed: alternative and conventional technologies will be: 154 Smart Grid to Enhance Power Transmission in Vietnam a. Hydropower at 11.8%; i. 500kV: 21,900 MVA (2014), ~+32% per year; b. Energy storage hydropower at 3.9%; ii. 220kV: 31,351 MVA (2014), ~+15% per year. c. Coal thermal power at 51.6%; D.3.8 Transmission network performances d. Gas fired power at 11.8% (of which LNG will be at 4.1%); The major indicators of service levels in an electrical net- work are SAIFI and SAIDI: e. Power using renewable energy at 9.4%; f. Nuclear power at 6.6%; and a. SAIFI (System Average Interruption Frequency Index) is the count of all extended outages over g. Imported power at 4.9%. the number of customers; b. SAIDI (System Average Interruption Duration D.3.7 Transmission network sizing Index) is the sum of all outage durations over the The eventual size of the transmission network in Vietnam number of customers. by 2030 is based on the following assumptions: During 2013 the SAIFI and SAIDI values for the Vietnam- ese transmission were respectively 27 ,975 interruption a. Based on the period between 2006–2014 the aver- events for a total of 4,461 minutes. age growth rate for various elements of the trans- mission network in Vietnam are predicted to be: Transmission network losses on the Vietnamese net- i. 500kV: 6,756 km (2014), ~+16%/year growth rate; work were running at 2.33% in 2015 distributed between technical and non-technical losses, which are estimated ii. 220kV: 12,513 km (2014), ~+6.6%/year growth rate; to be running at 70% to 30% respectively. These per- b. Transmission substations: 164 (2015), ~+7% new centages are based on international experiences as this substations/year; data is unavailable from the Vietnamese network. c. Transformers—The growth rate for these is based In 2014 the total cost of system operation is estimated to on the period from 2009 to 2014: be $400,000,000 per year (source: NPT). E. Identify and Quantify Benefits E.1 Key points summary Finally, the benefits in blackout prevention achievable with the deployment of Smart Grids are also investigated. The Following the JRC methodology, the first step of the cost international experience and also the Vietnamese one benefit analysis is to map the identified Smart Grid initia- regarding the cost and damages derived from a blackout tives to their functions within the transmission system. are important and these were the main drivers that pushed The second step is to map the function served to the the development of Smart Grids technologies in USA, benefit achieved from the Smart Grid application. This Europe and around the world. The benefits derived from chapter performs these mappings in order to identify the blackout prevention were considered but separately. specific range of benefits for each Smart Grid initiative. For each Smart Grid initiative, it has been possible to E.2 Mapping Assets to Functionalities quantify these direct benefits: Starting from the main categories of functionalities a. Direct Transmission OPEX reduction; described in JRC methodology, four of them have been selected to be use in this analysis. Each of them has been b. Reduction of energy not served; divided in sub-functionalities, which are tailored to the c. Reduction of power losses; Vietnamese specific Smart Grid roadmap context. These functionalities and the relative sub-functionalities are: d. Improved system reliability through a reduction in the frequency of system faults and their duration; and a. Enhancing efficiency in day to day grid operation, e. Avoided CAPEX for transmission system and composed by: Deferred Capacity Investments. i. Enhance network stability; To quantify the financial value of such benefits, some ii. Enhance efficiency in asset maintenance; and assumptions have been made for each Smart Grid ini- tiative. These assumptions have been made by the con- iii. Enhance efficiency in system operation. sultant based on international experience and has been b. Ensuring network security, system control and shared and discussed with the Vietnamese stakehold- quality of supply, composed by: ers prior to the analysis (during the meetings of the dis- i. Enhance network automation; covery process from April 21st to April 23rd 2015). These statements are summarized in Table 23. ii. Enhance network power quality; and iii. Fault reduction. Not only direct benefits have been investigated but also sys- tem level ones. Regarding them some considerations have c. Better planning of future network investment, been done; their monetization has not been investigated for composed by: each Smart Grid initiative, but it has been estimated in con- i. Enhance network development flexibility; nection with the deployment of Smart Grid initiatives. ii. Dispatching constraints reduction; The support to the integration of renewable energy gen- iii. Congestion reduction; and eration allowed by Smart grid development has been also iv. Upgrade network asset. analyzed. International experience, in fact, demonstrates that Smart Grid solutions can facilitate the integration of d. Improving market functioning and customer ser- RES whilst limiting the need for additional infrastructure vice, composed by: and improving the system operation. The contributions i. Facilitate market development. of the different Smart Grid initiatives are described, stat- ing that HVDC technology and Dynamic Thermal Circuit Table 24 maps the Smart Grid initiatives proposed in the Rating can be considered the best ones in terms of new technical analysis report with the functionalities that they variable renewable generation integration. perform in the transmission system. 155 156 Smart Grid to Enhance Power Transmission in Vietnam TABLE 23: SUMMARY OF BENEFITS MONETIZATION ASSUMPTIONS ON SMART GRID INITIATIVES Initiative Major assumptions regarding benefits • The SAS installation can contribute 60% to the global reduction of the OPEX for the transmission system. SAS • Average ENS reduction of 100 MWh per year for each substation equipped with SAS. • The ENS costs is 3,000 $/MWh. • WAMS installation can contribute 10% to the global reduction of the OPEX for the transmission system. • The total number of voltage collapse events account for about 10% brownout of the peak load per year amounting to a total of 30 minutes. WAMS • The prevention capacity is directly proportional to the pace of installation. • All the new substations brought on-line and 68 of the existing ones will be equipped with PMUs. • WAMS functions capable of ensuring the prevention of such events will be available 3 years after the project commences. • This application will result in a 20% reduction in the number of voltage collapse events if all substations have PMUs installed. • Lightning Location System installation can contribute 5% to the global reduction of the OPEX for the transmission system. Lightning • The phase-to-phase-to-ground faults caused by lightning account for 8% of the total number of the faults caused by lightning. Location • These events account for about 2% brownout of the peak load per year amounting to a total of 30 minutes. System • This application will result in a 25% reduction of phase-to-phase-to-ground faults caused by lightning. • The ability to prevent such events will be available after 3 years from the start of the project. • SVC installation can contribute 10% to the global reduction of the OPEX for the transmission system. • The total number of voltage collapse events cause approximately10% of brownouts of the peak load per year SVC accounting for a total of 30 minutes. • This application will result in a 25% reduction of the number of voltage collapse events. • A HVDC link can contribute 5% to the global reduction of the OPEX for the transmission system. • 500 kV and 2000 MW rated power for both AC and HVDC solution. • AC and HVDC lines have the same length. • The OPEX is calculated at 1.5% of the capital expenditure for both AC and HVDC lines. OPEX for converter stations is 3% of their CAPEX (source: manufacturers).. • Yearly energy losses are calculated with the following formula: HVDC oo L_year=8760 LF X L_Pmax, where: oo LF = 70% is the loss factor, corresponding to 6,132 equivalent hours; oo L_Pmax are the losses at rated power and depend on the type of the transmission (AC or HVDC) and the size of the conductors. • The financial value of energy losses is estimated to be 60 $/MWh per year. • The annual financial value of the reduction of power losses is based on the difference between the value of AC and HVDC energy losses per year. • These events account for about 10% brownout of the peak load per year amounting to a total of 30 minutes. FLS • The prevention capacity is directly proportional to the number of lines equipped with FLS devices. • This application will result in a 25% reduction of time lost because of faults. • Average cost of a transformer fault is approximately $9,000 per MVA and the fault probability is estimated to be about 0.6%. DGA • The installation of this device in transformers will prevent about 80% of faults. • Dynamic Thermal Circuit Rating can contribute 5% of the OPEX for the transmission system. Dynamic • It is proposed that four critical lines be equipped with DLR sensors. Thermal • These lines are 100km in length. Circuit Rating • The costs estimated for these four lines include the cost of the DLR solution (1 sensor every 10km) and of reconductoring. • A DLR sensor costs $32,000 while the reconductoring costs $200,000/km. • It is assumed that the GIS application will only be developed for the SAS initiative and it is expected to result in a 10% GIS reduction in the OPEX for the SAS project. • Power quality monitoring and Metering Data Acquisition Systems can contribute 5% to the global reduction of the Power quality OPEX for the transmission system.. monitoring and • The fault events caused by critical voltage dips account for about 1% brownout of the peak load per year amounting Metering Data to a total of 15 minutes. . Acquisition • The prevention capacity is directly proportional to the number of lines equipped with PQ devices.. Systems • This application will result in a reduction of fault time losses with Power Quality monitoring is about 20%. Source: Authors Volume 2: Cost-Benefit Analysis 157 TABLE 24: MAPPING ASSET TO FUNCTIONALITIES Ensuring network Enhancing efficiency security, system Improving market FUNCTIONALITIES in day-to-day control and quality Better planning of future functioning and grid operation of supply network investment customer service Enhance efficiency in asset maintenance Enhance network development flexibility Enhance efficiency in system operation Dispatching constraints reduction Enhance network power quality Facilitate market development Enhance network automation Enhance network stability Upgrade network asset Congestion reduction Fault reduction SMART GRID SOLUTIONS Substation Automation System • • • • Wide Area Monitoring System • • • • Lighting Location System • • • Static Var Compensator • • • • • High Voltage Direct • • • • Current technology Fault Locator System • Power quality monitoring system • • • • On-line Dissolved • • • Gas-in-oil Analysis Dynamic Thermal Circuit Rating • • • • • Geographic Information Systems • • Metering Data Acquisition System • • • Source: Authors For each initiative, the reasons for this mapping are: developed using PMUs data, WAMS initiative can “Enhance network stability” (both voltage and a. Substation Automation System (SAS). It is evi- transient stability) and also can “Enhance effi- dent that this initiative “Enhances network auto- ciency in system operation” . As in SAS case, the mation” and consequently “Enhances efficiency installation of new devices “Upgrade network in asset maintenance” . Further, it “Upgrades asset” . In the end, with a successful exploitation network asset” thanks to the installation of new of WAMS functions it is possible to achieve a con- components (i.e. IED). Finally, as stated in the sistent “Fault reduction”. technical analysis report, SAS monitoring capac- c. Lightning Location System. The main purpose ity leads to a “Fault reduction”. of this solution is the “Fault reduction”, thanks b. Wide Area Monitoring System (WAMS). to its capacity to avoid transient faults due to Thanks to the monitoring application that can be lightning. Transient faults reduction allows to 158 Smart Grid to Enhance Power Transmission in Vietnam “Enhance network power quality” Further, the j. Geographic Information Systems (GIS): The availability of a Lightning Location System data availability of a GIS for initiative for asset man- in remote control and dispatching centers can agement and/or system operation allows to “Enhance efficiency in system operation” . “Enhance efficiency in asset maintenance” and to “Enhance efficiency in system operation” . d. Static Var Compensator (SVC): A proper installation and exploitation of SVC devices can k. Metering Data Acquisition System. This “Enhance network stability” (as for WAMS case, measurement system is a key element and an both voltage and transient stability) and also enabling technology for the achievement of an can “Enhance efficiency in system operation” . open energy market, so its main functionality is Moreover, this technology allows achieving a “Facilitate market development” . Consequently “Dispatching constraints reduction” and a “Con- the availability of such measurements allows gestion reduction”; such reductions remove con- to “Enhance efficiency in system operation” . straints from network growing process and so Finally, the installation of new devices allows to “Enhance network development flexibility” . “Upgrade network asset” . e. High Voltage Direct Current (HVDC) technol- ogy: Building an HVDC link allows achieving a E.3 Mapping Functionalities to “Dispatching constraints reduction” and a “Con- Benefits gestion reduction”; such reductions remove con- straints from network growing process and so For the second step, five transmission system benefits “Enhance network development flexibility”. have been identified to map the functionalities of Table f. Fault Locator System. This initiative can con- 24. These benefits derive from the generic direct ben- tribute to time and cost reduction of asset main- efits (see section ‘D.2’) and from JRC methodology, but tenance, therefore its main functionality is to they have been properly tailored to the specific Smart “Enhance efficiency in asset maintenance” . Grid roadmap context, in order to fit Vietnamese global policy targets in the electricity sector. These benefits are: g. Power quality monitoring system. The main purpose of this initiative is to “Enhance network a. Direct Transmission OPEX reduction (automa- power quality” and consequently to “Enhance tion and operational efficiency). Regarding the efficiency in system operation” . Moreover, as optimization of operating costs due to automated stated in the Technical Analysis report, a suitable operations reported savings ranging between KPI is the percentage reduction of voltage deeps -5% and -10% have been assumed considering and in some cases these events can cause out- international experiences (e.g. Italian case, feasi- ages. Consequent, one of most important func- bility study performed in Serbia and ECRA project . tionalities of this initiative is “Fault reduction” in Smart Grids2). Such benefits can of course vary Finally, the installation of new devices allows to significantly according to specific network char- “Upgrade network asset” . acteristics and architecture, intensity and produc- h. On-line Dissolved Gas-in-oil Analysis (DGA). tivity of resources involved in network operations The installation of the DGA monitoring devices and maintenance and level of provided service. “Upgrade network asset” . Their prevention capa- The literature on this issue is quite poor and a bility of transformer faults allows achieving trans- detailed study would be necessary to obtain former “Fault reduction” and consequently to the exact value of expected Direct Transmission “Enhance efficiency in asset maintenance” . OPEX reduction for Vietnam. Such exhaustive analysis is outside the scope of this work, so a i. Dynamic Thermal Circuit Rating (DTCR): This conservative estimation of this value can be con- , allows achiev- initiative, increasing line “ampacity” sidered functional to the benefits monetization ing a “Dispatching constraints reduction” and a performed in this CBA. Therefore, relying on con- “Congestion reduction”; such reductions remove sultant experience earned in dealing with similar constraints from network growing process and international projects, and taking into account so “Enhance network development flexibility” . the Vietnamese scenario, the value of operating Moreover, this constraints reduction allows to cost reduction potentially allowed by a Smart “Enhance efficiency in system operation” . Grid development has been assumed equal to -8%. The various Smart Grid initiatives contribute in different ways to achieve this objective; the Volume 2: Cost-Benefit Analysis 159 estimations of their contribution are described in Energy Not Served (ENS), which can be monetized paragraph ‘E.4’. To perform such estimation the as in “Reduction of energy not served” case. potential impact of the different initiatives has f. Avoided CAPEX and Deferred Capacity Invest- been evaluated, assigning the highest contribu- ments. The implementation of Smart Grid ini- tion to SAS because this Smart Grid application tiatives provides the transmission network of involves a large amount of people working on function and devices that can solve incident the transmission network. To some other initia- issues definitely or for a consistent time interval tives, like WAMS or LLS, a lower value has been (some years). In the first case the Smart solution assigned because they involves only resources fixes the problem completely, so it is possible (in terms of people and money) related to remote to identify an “Avoided CAPEX” benefit, shun- control center. ning an investment in conventional transmission b. Reduction of energy not served: This ben- network components (e.g. lines, power plants, efit considers the prevented Energy Not Served etc.). In the second case the Smart solution is (ENS), which is a typical KPI considered in Cost- not definitely but can put off to a later time an Benefit Analyses. The procedure to monetize is investment, therefore it possible to identify this described in paragraph ‘E.4.1’. benefit as “Deferred Capacity Investments” . c. Reduction of power losses. The reduction of Table 25 maps the functionalities identified with the ben- technical losses on the electrical transmission efits just listed. For each sub-functionality, the reasons network due to automated control of grid voltage for this mapping are: and power factors systems, optimization of load dispatching and management has been assumed a. Enhance network stability. This functionality equal to -10% of technical losses value (a more aims to increase transmission network reliability ambitious figure would be 20%), according to both in terms of ”Reduction of energy not served” international experiences. Assuming technical and of “Improving system reliability through losses equal to 1.63% of energy consumption reduced frequency and duration of system faults”. such losses are therefore assumed to reduce by 0.16% at the end of the 15 years period. This b. Enhance efficiency in asset maintenance. This statement sets up a reliable objective for the functionality aims achieving a “Direct Transmis- whole Smart Grid roadmap implementation, but sion OPEX reduction” thanks to the increased in this CBA the monetization of the reduction of automation efficiency. power losses has been considered only for HVDC c. Enhance efficiency in system operation. This initiative (see paragraph ‘E.4.6’). functionality aims achieving a “Direct Transmis- d. Improve system reliability through reduced sion OPEX reduction” thanks to the increased frequency and duration of system faults. This operational efficiency. benefit considers the reduced duration and fre- d. Enhance network automation. This functional- quency of outages due to automated responses ity increases automation efficiency and so allows to some types of faults and faster scouting and a “Direct Transmission OPEX reduction” . Further it repair for others. To evaluate this improvement in aims to increase transmission network reliability reliability of power supply the values proposed in both in terms of ”Reduction of energy not served” the “DECISION: APPROVAL OF SMART GRID and of “Improving system reliability through DEVELOPMENT PROJECT IN VIETNAM, Novem- reduced frequency and duration of system faults”. ber 2012” has been considered. This document assumes that, after each 5 years period, the e. Enhance network power quality. Like “Enhance Smart Grid development allows the following network stability” functionality also this one aims potential reduction: to increase transmission network reliability both in terms of ”Reduction of energy not served” and i. System average interruption frequency index of “Improving system reliability through reduced (SAIFI) will be reduced 10%; and frequency and duration of system faults” . ii. System average interruption duration index f. Fault reduction. Thanks to fault reduction it is (SAIDI) will be reduced 20%. possible to increase transmission network reli- e. This benefit, thanks to the reduction of duration ability both in terms of ”Reduction of energy and frequency of outages, allow a reduction of not served” and of “Improving system reliability 160 Smart Grid to Enhance Power Transmission in Vietnam TABLE 25: MAPPING FUNCTIONALITIES TO BENEFITS Ensuring network Enhancing efficiency security, system Improving market FUNCTIONALITIES in day-to-day control and quality Better planning of future functioning and grid operation of supply network investment customer service Enhance efficiency in asset maintenance Enhance network development flexibility Enhance efficiency in system operation Dispatching constraints reduction Enhance network power quality Facilitate market development Enhance network automation Enhance network stability Upgrade network asset Congestion reduction Fault reduction BENEFITS Direct Transmission OPEX reduction (automation and • • • • • • • • operational efficiency) Reduction of energy not served • • • • • • Reduction of power losses • • Improve system reliability through reduced frequency • • • • • • • and duration of system faults Avoided CAPEX and Deferred • • • • Capacity Investments Source: Authors through reduced frequency and duration of sys- transmission network reliability both in terms tem faults” . Consequently a “Direct Transmission of ”Reduction of energy not served” and of OPEX reduction” is achievable. “Improving system reliability through reduced . frequency and duration of system faults” g. Enhance network development flexibility. This functionality, performed by some Smart Grid i. Congestion reduction. For the same reasons solutions that aim to reduce network topology stated for “Dispatching constraints reduction” , constraints, facilitates electrical network growing also this functionality carries out “Direct Trans- process. So the main benefit is “Avoided CAPEX mission OPEX reduction” , ”Reduction of power and Deferred Capacity Investments” . losses”, ”Reduction of energy not served” and “Improving system reliability through reduced h. Dispatching constraints reduction. This reduc- frequency and duration of system faults” . tion enhances efficiency in daytoday system operation allowing “Direct Transmission OPEX j. Upgrade network asset. The installation of new reduction” and ”Reduction of power losses” . Fur- devices, necessary for some smart grid initiative ther, an easier dispatching can avoid the majority deployment, can avoid or put off to a later time an of critical situations to take place in the electri- investment on the electrical network. So the main cal network. Therefore, it is possible to increase benefit is “Avoided CAPEX and Deferred Capacity Volume 2: Cost-Benefit Analysis 161 Investments”. Moreover, the efficiency of these Whilst the current average Vietnamese VoLL compares update equipment allows a “Direct Transmission quite favorably with the mature transmission networks OPEX reduction” and “Improves system reliabil- of Europe and the USA, the failures are frequent enough ity through reduced frequency and duration of to hinder current industrial development. They are also a system faults” . significant disincentive to new industrial investments as reported to Bloomberg by many sources from the Indus- k. Facilitate market development. The electrical trial Zones Management Authority ([2] [3] [4]). In this con- market is comprised by different phases; among text the ENS or VoLL value is too high for the industrial them there is the ancillary market which carries out sector despite the perception of the average residential a “Direct Transmission OPEX reduction” , allowing to customers. dispatch the most convenient power sources. The continuing growth of the Vietnamese industrial sec- E.4 Benefits monetization tor is placing an ever increasing load on the electrical net- work thus causing the ENS value to increase. The annual To conclude the benefit analysis it is fundamental to increase of peak load is currently running at +9% and is a determine how these benefits are monetized. The fol- trend that is expected to continue over the next 15 years. lowing paragraph discusses the monetization of the It is a simple economic truth that demand is directly pro- reduction of “Energy Not Served” . The subsequent portional to value and as the demand for electricity by the paragraphs from ‘E.4.2’ to ‘E.4.11’ repeats this process Vietnamese industrial sector increases so does the value for each Smart Grid initiative. of that energy, which means that every outage increases the net value of income lost. The NPT wish to implement both Power Quality monitor- ing and Metering Data Acquisition System. Whilst these One of the key targets for the development of the Viet- two applications are quite different and independent, namese transmission system is increased network avail- they are both able to use the same measuring device. ability and reliability. A country with a low VoLL is a clear Thus it is worth implementing both these applications signal that system reliability is not an issue and therefore as this will maximize the investment in the measuring there is no compelling case for Smart Grid initiatives. devices which will be widely deployed across the Viet- Conversely, a country with an increasing VoLL, like Viet- namese power network. nam, is in urgent need of Smart Grid applications in order to address the problem. Chapter ‘G’ balances the costs of each Smart Grid appli- cation with the benefits it will deliver and use the all the The importance of addressing the ENS issue is borne out assumptions articulated in this section. by the experiences of both developing and developed countries [5]. The report calculates the monetary value of VoLL, i.e. ENS, and finds that it lies between 2 and E.4.1 Monetization of Energy Not Served 5k $/MWh for developing countries. Whilst Vietnam is a reduction developing country, it is a “fast” developing country, far faster than any other developing country in Africa or Asia. Prior to commencing the cost benefit analysis of each Smart Grid initiative, it is worth considering the value of Therefore, given: lost load (VoLL), usually measured in $ per Megawatt ($/MW), which is what happens every time there is a a. That international references for developing coun- service interruption (i.e. brownout or blackout) duration. tries calculate the VoLL or the ENS to lie between 2 and 5k $/MWh; This parameter provides a means of calculating the finan- cial value of a reduction in Energy Not Served (ENS) (see b. That the current Vietnamese Smart Grid develop- Table 25, “Reduced energy not served”). The reduc- ment roadmap aims to enhance network reliability; tion of the regular outages and brownouts that occur c. That the current and emerging Vietnamese indus- on the Vietnamese network is one of the key outcomes trial sector is making considerable demands on expected of the Smart Grid development, which is why it the power network, which impacts the value of is important to evaluate them in terms of financial bene- the ENS; and fits. The ENS value is a useful way of equating the power outages to a financial value which can then be translated d. It is reasonable to ascribe a value of $3,000 per into a return on investment over time. unserved MWh for the whole CBA timeframe. 162 Smart Grid to Enhance Power Transmission in Vietnam This begs the question as to whether this value should served” and “Improve system reliability through be applied as a flat rate or varied as a function of the . reduced frequency and duration of system faults” duration of the power outage. Whilst most VoLL calcula- tions do apply a fixed rate, some countries such as Bra- In order to estimate the amount of ENS reduction for zil use a sliding scale, (a block decreasing or increasing some of the initiatives it has been assumed that a definite mechanism) or even a curve that maps the variation of type of regular fault event on the transmission network this value according to the duration of the interruption. (e.g.: voltage collapse) causes a number of brownouts per year corresponding to a percentage of the peak load NARUC, or “The National Association of Regulatory Util- (e.g. 10%) that lasts a certain number of minutes (e.g. ity Commissioners” developed a method for evaluating 30 minutes). the cost of ENS as a function of the outage duration [6]. This approach, which has been widely accepted by the electri- cal industry as a whole, takes the view that a short inter- E.4.2 Substation Automation System (SAS) ruption has a higher relative cost than a long brownout. According to ERAV [7], the Vietnamese grid in general is not a modern system and has a low level of automation. Finally, the NARUC mechanism is used to weight the cost Substation automation adds a lot of value and is a signifi- of an interruption depending on its duration. This approach cant step in the direction of creating a more modern and has been applied to the value of 3,000 $/MWh assumed reliable grid. for the Vietnamese network in order to create a table of interruption duration against cost (see Table 26 below). The values in this table have been TABLE 26: INTERRUPTION COST DEPENDING ON INTERRUPTION DURATION graphed to provide an at-a-glance illustra- tion of the interruption cost ($/MWh) as shown in Figure 85. interruption duration (min) interruption cost ($/MW) Chapter ‘H’ provides a sensitivity analy- 1 522 sis of ENS cost which further refines the effect of such assumptions on the 20 1,215 benefits conferred by the Smart Grid initiatives. 120 3,000 240 9,459 The following paragraphs (from ‘E.4.2’ to ‘E.4.11’) evaluate the benefits derived 480 22,914 from Smart Grid solutions and how Source: Authors they will enable “Reduced energy not FIGURE 85: INTERRUPTION COST ($/MWH) DEPENDING ON INTERRUPTION DURATION Source: Authors Volume 2: Cost-Benefit Analysis 163 The benefits of SAS functionality are: E.4.3 Wide Area Monitoring System (WAMS) The benefits of WAMS functionalities the consequent a. Direct Transmission OPEX reduction; and benefits are: b. Improved system reliability through reducing fre- quency and duration of system faults. a. Direct Transmission OPEX reduction; and b. Reduction of energy not served. Paragraph ‘E.3’ discussed a reduction of 8% in the OPEX for the transmission system and stated that a SAS instal- For the first one it has been assumed that WAMS can lation can contribute up to 60% of this 8% of cost reduc- contribute up to 0.8% to the reduction of transmission tion, i.e. 4.8% of reduction. Given that the transmission system OPEX. The expected reduction is $3,200,000 system OPEX is $400,000,000 (according to NPT) then based on a transmission system OPEX of $400,000,000 the expected reduction is $19,200,000. This 60% reduc- (information from NPT). tion value is the highest contribution to the global reduc- tion of transmission system OPEX of all the proposed The overheads in terms of headcount and resources for Smart Grid initiatives. This estimation is based on: WAMS are less than for SAS, so 0.8% (compared with SAS 4.8%) can be considered as a conservative and reli- a. The consultant’s experience gained from the Ital- able estimation. Such evaluation is based on the experi- ian SAS project development; ence earned from the Italian WAMS development. b. The high cost overheads in terms of personnel and resources dedicated to the transmission net- For the second benefit, as stated in the technical analy- work means that even a low reduction of such sis report, the evaluation of the success of WAMS initia- significant costs can lead to a sizable saving; and tive is very complex strictly dependent on the functions developed using PMU data. According to the USA experi- c. As most of the Vietnamese substations are man- ence of installing PMUs [9], the benefits are quoted to be ually controlled, the advent of SAS will automate much higher than the costs. This is despite the relatively a large number of operations and controls leading high cost of $80,000 per PMU as they were among the to reduction of the OPEX costs. first to adopt this technology. The second benefit, as stated in the technical analysis report, is the key performance indicator (KPI) referring to A voltage stability monitoring feature based on WAMS the reduction of Energy Not Served (ENS). Toward this [10] [11] can be considered a success if it helps to prevent end, it has been assumed that: 15%-35% of voltage collapses. The percentage depends on the topology of the portion of the network involved in a. An average value of annually ENS reduction per the voltage instability event. substation equipped with SAS is 100 MWh; and To estimate the benefits of the WAMS initiative in terms b. The ENS costs according to what determined in of “Reduction of energy not served” it has been paragraph ‘E.4.1’. assumed that: This expected direct benefit of SAS is the prevention of a. The total number of voltage collapse events faults or the reduction of the outage time (thanks to the cause about 10% brownout of the peak load per automated and detailed diagnostic) at substation level year amounting to a total of 30 minutes; with a consequent ENS reduction. Some evaluations of the Italian SAS, international experience [8] and the b. The distribution variation of PMUs across the typical guaranteed performance of SAS device has led to transmission network will result in varying levels estimating an average value of annually ENS reduction of prevention of these events. The prevention of 100 MWh per substation equipped with SAS. Since capacity is directly proportional to the pace of this value can change depending on the type of fault, installation (number of substation equipped with 100 MWh represents a conservative estimation. PMU); c. All the new substations installed and 68 of the Therefore, it has been possible to estimate the benefits old ones will be equipped with PMUs; and of this Smart Grid initiative in terms of ”Improve system reliability through reduced frequency and duration of d. WAMS functions allowing the prevention such system faults” . events will be available after 3 years from the 164 Smart Grid to Enhance Power Transmission in Vietnam beginning of the project (2015) and its prevention a. The phase-to-phase-to-ground faults caused by capacity is estimated to be 20% if all the substa- lightning are about 8% of the total number of the tions are equipped with PMUs. faults caused by lightning; b. These events cause an equivalent 2% brown- It is worth underlining that one of the Vietnamese trans- out of the peak load per year lasting for a total mission network issues is voltage stability [12]. Voltage elapsed time of 30 minutes; collapse events are typical phenomena caused by this type of issue and though short in duration (conservative c. The reduction of phase-to-phase-to-ground faults average 30 minutes) they can involve large areas of the caused by lightning provided by a TLSA installa- transmission network (i.e. 10% brownout of the peak tion driven by LLS is 25% more than a generic load per year). Such estimations are based on some out- equipping of lines with TLSAs; and ages that occurred in Italy. An effective prevention of d. The ability to avoid such events will be available 3 voltage collapses can be performed only with online cal- years after the start of the project (2015). culations and it is worth highlighting the value of WAMS based applications for this requirement. The real added It has not been possible to estimate the direct benefit value of WAMS in the prevention of voltage collapses is of this solution in terms of “Reduction of energy not the up-to-date and accurate information together with served” . All these assumptions are based on the consul- the availability of phase measurements. tant’s experience in designing, developing and support- ing the operation of the Italian LLS [13]. E.4.4 Lightning Location System (LLS) E.4.5 Static Var Compensator (SVC) The benefits of “Lightning Location System” functions are: The benefits of SVC functionality are: a. Direct Transmission OPEX reduction; and a. Direct Transmission OPEX reduction; and b. Reduction of energy not served. b. Reduction of energy not served. The first benefit is carried out by the availability of a For the first one it has been assumed that the SVC initia- Lightning Location System data in remote control and tive contributes up to 0.8% of reduction of transmission dispatching centers. It has been assumed this initiative system OPEX. This represents 10% of the global reduc- can contribute to 0.4% of reduction of transmission sys- tion of transmission system OPEX (starting at 8% based tem OPEX. This means 5% of the global 8% reduction as on the applications discussed up to that point as stated stated in paragraph ‘E.3’. According information received in paragraph ‘E.3’). The expected reduction is equal to from NPT the transmission system OPEX are equal to $3.2 million based on a transmission system OPEX of $400 million, the 5% of the expected reduction is equal $400 million (information from NPT). This estimation is to $1.6 million. based on the European experience with SVC installation and this reduction is due to two main causes: For the second benefit, as stated in the technical analy- sis report, it has been considered that thanks to Light- a. These devices operate on a “set and forget” prin- ning Location System and the consequent Transmission ciple; and Surge Line Arresters (TLSA) installation it is possible to reduce the transient faults caused by lightning. Willing b. They allow more efficient and flexible daily net- to avoid the use of three phase reclosing (which creates work operations. great stresses to transformers and generators), the fault For the second benefit, as stated in the technical analysis reduction allowed by this Smart Grid initiative could be report, is that such a system can effectively help to pre- useful in those cases in which the faults caused by light- vent 15%-35% of voltage collapses in the portion of the ning are phase-to-phase-to-ground, so they cannot be network influenced by its effects [14], [15], [16]. cleared by a single pole reclosing. Therefore, knowing that NPT will however install TLSAs, for the LLS benefit According to the NLDC, one of the difficulties for volt- evaluation in term of “Reduction of energy not served” age regulation is that most of the shunt reactors are the incremental fault reduction achievable with a TLSA directly connected to the lines without circuit breakers, installation driven by a LLS is considered. which causes inflexibility in the operation of the system. The NLDC is promoting research and development of Thus, it has been assumed that: switchable inductors and/or controllable compensators, Volume 2: Cost-Benefit Analysis 165 like SVCs [17]. Additionally the seventh Master Plan also Thus, a very conservative approach has been used that considers research on using FACTS, SVC devices in order assesses the most appropriate technology for a link to increase transmission limits and deliver a step change between currently independent power systems. The modernization of the control system [17]. choice is between a legacy or “normal” AC system or one based on HVDC technology. This approach will The evaluation of the benefits of SVC is based on the ensure a robust solution appropriate for both current and conservative assumption that the total number of volt- predicted requirements. age collapses cause approximately 10% brownout of the peak load per year for an elapsed total time of 30 min- The basis for the assessment is a conservative one as utes. This solution will be considered a success if it is it considers only the direct benefits. Wider system level able to reduce the incidence of these events by 25%. benefits are not internalized but it is important to high- light that HVDC technology is the most versatile Smart Grid initiative to integrate with new variable renewable E.4.6 High Voltage Direct Current (HVDC) generation. In fact the inherent increased transfer capac- technology ity and active power control of HVDC are fundamental According to the NLDC [18], there is certain to be more benefits, which will allow the power generated from cooperation and power exchange with neighboring coun- wind or solar power plants to be easily absorbed by bal- tries in the near future. Such interconnections will bring ancing the natural fluctuation of renewables. similar benefits by unifying regional sub-systems within a nation. Besides, this is also an opportunity to develop A comparison of the relative costs and benefits of the an inter-country power market, possibly between coun- two technologies shows that HVDC has a higher initial tries in the Indochina peninsula or even other Asian coun- install cost because of the converter stations, while tries. However, interconnection with other countries may the overhead lines or the cables are less expensive per create new challenges for the operational systems in kilometer. Additionally, HVDC lines become more cost Vietnam. efficient as the distance increases since the cost of the converter stations can be amortized over the line length. The idea of promoting interconnection between the Given the higher install expense and lower line cost of southern grid in China and the Vietnamese grid through HVDC over AC the break-even point will be related to the HVDC at 500kV has been considered for few years. By overall length of the link required. using HVDC technology Vietnam hopes to resolve the cur- rent issue of operating disparate systems. At the same The financial valuation of the direct technical benefits of time, the power exchange with the neighboring countries HVDC are as follow; will become safer [19] . Additionally, the seventh Master Plan also considers the possibility of having HVDC links a. The “Reduction of power losses” . This benefit is and has established research programs for the develop- strictly related to the lower cost per km of DC ment of transmission networks at voltage levels of 750 lines relative to AC ones. The lower cost allows a kV, 1,000 kV and HVDC for use after 2020 [17]. greater length and thus a lower resistance, which in turn reduces power losses; An incremental analysis has been performed for the eval- b. The “Direct Transmission OPEX reduction” . As uation of the HVDC initiative. It is not possible to do a full the operational costs of the HVDC have been cost benefit analysis because the benefit derived from the taken into account in the costs list, the cor- installation of a new line is something to be determined responding OPEX of the AC line too has to be on a case-by-case basis and cannot be generalized. But taken into account as a benefit. In addition, it has since the benefit of the new line, in terms of optimization been assumed that the HVDC link can contribute of energy mix, is independent from the technology used 0.4% to the global reduction of the OPEX for the (AC or DC), an incremental cost benefit analysis is really transmission system. The expected reduction is useful to understand the impact of the adoption of a DC $1,600,000 considering a transmission system line instead of an AC one. This also highlights the further OPEX value of $400,000,000, a figure provided benefits that derive from using DC technology instead by NPT. of the traditional AC system. The construction of a new HVDC line is not a smart initiative in itself, rather the truly c. This estimation is based on the consultant’s broad smart aspect is the choice of HVDC technology with its experience with HVDC as well as its greater effi- inherent features and characteristics for already planned ciency and flexibility for daily network operations. links instead of using traditional AC lines. 166 Smart Grid to Enhance Power Transmission in Vietnam The incremental costs of the HVDC link relative to the iv. LPmax are the losses at rated power and depend HVAC solution are described in chapter ‘F’, while the on the type of the transmission (AC or HVDC) main assumptions for calculating and estimating the and the size of the conductors. reduction of power losses benefit are as follows; f. Energy losses have been valued at 60 $/MWh for the annual energy losses as depicted in the histo- a. 500 kV and 2,000 MW rated power for both AC gram shown in Figure 86 below. and HVDC solution; g. The financial value of the annual power loss b. AC and HVDC lines have the same length; reduction is the difference between the cost of c. Converter stations losses are 1.2% at rated power; AC and HVDC annual energy losses. d. The sizing of the conductors is optimized sepa- It is important to underline that the financial valuation rately for AC and HVDC. The sizing of the section of benefits has deliberately omitted some of the advan- is made by balancing of the investment cost of tages HVDC technology has over HVAC: the line with the cost of losses over 15 years (optimum conductors to minimize investment a. HVDC power transmission between networks plus capitalized cost of losses); can operate either asynchronously or at different frequencies; e. Yearly energy losses have been calculated using the following formula: b. HVDC technology does not increase the short- circuit ratio of the AC system; c. HVDC lines have a better lightning performance where: than AC. iii. LF = 70% is the loss factor3, corresponding to 6,132 equivalent hours4; FIGURE 86: ELECTRICITY GENERATION COSTS IN SOUTH-EAST ASIA UNDER DIFFERENT COAL AND GAS PRICE ASSUMPTIONS, 2020-2035 Source: IEA, 2013, (2) Volume 2: Cost-Benefit Analysis 167 E.4.7 Fault Locator System (FLS) Table 27 below shows the comparative numbers for outage events and duration from developed economies This initiative can contribute to a reduction in the time around the world. and cost of asset maintenance. In particular, as stated in the technical analysis report, the installation of a fault As discovered earlier with voltage collapse events, even locator system can reduce the time taken by mainte- if an outage event lasts an average of 30 minutes it can nance crews to attend the site of an outage and reduce involve large areas of the transmission network (i.e. 10% the actual outage duration by 25%. brownout of the peak load per year). The reduction of fault time is a typical benefit achievable with such FLS devices. Whilst the reduction in the time taken to attend the fault Further, based on the fact that such devices can save hours location by maintenance crews is a highly desirable out- of time [21] to pinpoint the precise fault location, it is rea- come, the fact is that it is negligible compared to the related sonable to estimate a 25% reduction in the time taken. outage duration and consequent ENS cost. In order to calcu- late a financial value for this benefit in terms of “Reduc- tion of energy not served” it has been assumed that: E.4.8 On-line Dissolved Gas-in-oil Analysis a. The total number of these fault events amount (DGA) to about 10% brownout of the peak load per year According to a study performed by “The Hartford Steam and lasts for a duration of 30 minutes; Boiler Inspection and Insurance Company” in the USA b. The prevention capacity of this solution is directly the average cost of a transformer fault (and that’s only for proportional to the number of lines equipped with property damage) is approximately $9,000 per MVA and FLS devices. The greater the percentage of lines the fault probability is 0.6% [22]. protected the greater the prevention capacity; It has been assumed that: c. The percentage of fault time reduction achievable with FLS is estimated at 25%. a. The a DGA device installed in a transformer can prevent 80% of its faults (based on industry stan- At the time of writing it is known that the Vietnamese dard diagnostics techniques [23]); network experiences an entirely non-trivial number of faults each lasting for a significant amount of time5. The b. All new transformers installed in Vietnam will be total number of interruptions is about 28 per customer, provided with such monitoring devices; and each with an average duration of 2 hours and 40 minutes. c. From 2015 to 2030 the capacity of transformers The total number of minutes that an average Vietnamese 500/220kV will increase from 53,251  MVA to customer experiences power outages is 4,461 minutes 261,303 MVA. per year, equivalent to 74 hours. The average number of outage events in Vietnam is some 14 times greater than The installation of a DGA in a transformer will result in in Europe and America and the accumulated duration “Avoided CAPEX” reduction of 80%. nearly 40 times greater. TABLE 27: WORLDWIDE DEVELOPED ECONOMIES SAIDI AND SAIFI VALUES Source: University of Cambridge, 2012, (3) 168 Smart Grid to Enhance Power Transmission in Vietnam E.4.9 Dynamic Thermal Circuit Rating (DTCR) To estimate benefits in terms of “Avoided CAPEX and Deferred Capacity Investments” it has been assumed As stated in the technical analysis report, a good approach that: to verify the financial benefits of DTCR technologies to the transmission owner is to calculate the cost savings a. Four critical lines have been selected to be that DTCR systems unlock thus precluding the immedi- equipped with DLR sensors; ate need for more extensive capital investments. Figure 87 compares different approaches for increasing rat- b. The length of these lines is approximately 100km; ings ranging from line rebuilds, reconductorings to DLR c. For all of these lines are considered both the cost installations. of DLR solution (1 sensor every 10km) and of reconductoring; and It is worth noting that the installation of DLR systems is often only a fraction of the cost of other solutions though d. The cost of each DLR sensor is $32,000 while the they do offer lower capacities than other transmission reconductoring cost is $200,000/km. upgrades. Dynamic Thermal Circuit Rating can also contribute In those cases where the “ampacity” increase allowed 0.45% to the reduction in the OPEX for the transmission by DLR is sufficient for system operational purposes it is system. This represents a saving of $1,600,000 based possible to estimate benefits in term of “Avoided CAPEX on NPT’s figure of $400,000,000 OPEX for the transmis- and Deferred Capacity Investments” . Using DLR makes sion system. The increased loading limit supported by it possible to avoid or postpone line rebuild/reconductor- the DLR application also contributes to reduce the daily ing, thus avoiding or deferring this type of investment. operational costs. These estimations are based on the In particular, in a fast growing electrical system like Viet- DLR project implemented in Italy by Terna. namese one, it may happen that the overloading of some lines is only temporarily as the building of new assets (lines, power plants, etc.) can change the location of the E.4.10 Geographic Information Systems (GIS) most overloaded lines. Therefore, the rebuild/reconduc- The main benefit of the GIS application is the “Direct toring of the line could be completely useless and the Transmission OPEX reduction” . If the GIS application is use of DLR is recommended. developed exclusively for the SAS initiative, the benefit FIGURE 87: ALTERNATIVE SOLUTIONS COMPARISON TO INCREASE LINE “AMPACITY” Source: U.S. Department of Energy, 2014, (4) Volume 2: Cost-Benefit Analysis 169 will result in a 10% reduction of the total OPEX of the Power quality monitoring and Metering Data Acquisition SAS project. As with FLS, this estimation is based on the Systems can also contribute 5% to the global reduction elapsed time that is saved in locating faults or problems, of OPEX for the transmission system (as part of the 8% especially with remotely controlled equipment as in the reduction discussed in paragraph ‘E.3’). According to case of SAS. information received from NPT the transmission system OPEX is equal to $400,000,000 and a 5% reduction is equal to $1,600,000. E.4.11 Power quality monitoring and Metering Data Acquisition Systems The reductions in OPEX costs and fault times are benefits In order to assign a financial value to “Power quality conferred by these two Smart Grid applications and the monitoring and Metering Data Acquisition Systems” the estimations of the percentage amounts are based on the most important functionality to consider is the “Fault consultant’s experience of developing the Italian Power reduction” delivered by the Power quality monitoring sys- Quality system in partnership with TERNA (Italian TSO). tem development. In fact, considering the “Reduction of energy not served” benefit of this Smart Grind initia- tive, all the other benefits are negligible or too variable E.5 Assumptions about System Level (e.g. “Direct Transmission OPEX reduction” achievable Benefits thanks to the development of an electricity market) to be assigned a financial value. At a system level the benefits conferred by the Smart Grid initiatives, as discussed in paragraph ‘D.2’, include As stated in the technical analysis report, the power qual- ease of integration of renewable energy sources and ity monitoring development can reduce voltage dips. thus a reduced need for additional fossil fuel-based These events in some cases can cause outages that power capacity. entail an amount of ENS. While Smart Grid solutions will specifically enable the inte- Thus, to estimate benefits in terms of “Reduction of gration of distributed renewable sources in the transmis- energy not served” it has been assumed that: sion network they will also support a more efficient and balanced use of the whole energy generation capacity. a. The total amount of the faults events caused by critical voltage dips are equivalent to a 1% brown- These benefits are not related to a particular Smart Grid out of the peak load per year amounting to a total initiative but are the cumulative effect of the synergies elapsed time of 15 minutes; between many of the Smart Grids technologies deployed in the transmission network. While direct benefits in the b. The prevention capacity of PQ Monitoring is preceding section were calculated for each Smart Grid directly proportional to the number of monitoring application, this section looks at assigning a value to the devices installed on the power transmission net- system level benefits conferred by the deployment of work. The greater the number of devices installed, Smart Grids technologies. the better the prevention and the greater the cost savings; In order to be conservative and not overstate the case c. Power Quality monitoring can reduce fault times for Smart Grid technologies, the value assigned to the by 20%. system level benefits have not been factored into either the indicators or the economic evaluation of each Smart Voltages dips are typical phenomena on an electricity Grid initiative. However, such benefits have been quanti- transmission network plagued by voltage stability issues. fied and assigned a financial value for the whole Smart Such events are less critical than voltage collapses both Grid roadmap implementation. This global evaluation in terms of duration and in terms of the size of the highlights how the investments in developing a certain affected area. For this reason the equivalent event dura- number of Smart Grid solutions will benefit the perfor- tion has been reduced to 15 minutes and the equivalent mance, management and operational cost reduction of brownout of the peak load per year has been decreased the power system in Vietnam, to 1%. Nevertheless voltage dips have to be considered as a serious issue given the current and predicted indus- According to the Power Development Master Plan, Viet- trial development in Vietnam. Such phenomena can and nam’s purpose is to prioritize the development of renew- do cause significant damage to industrial plant in facto- able energy sources for electricity generation, increasing ries, especially ones manufacturing high value products. the percentage of electricity produced by these energy 170 Smart Grid to Enhance Power Transmission in Vietnam sources from 3.5% of total electricity production in 2010 to 4.5% in 2020 and 6.0% in 2030. In particular, FIGURE 88: STABILIZED COST OF ELECTRICITY (LCOE) FOR NEW the aim is to bring the total wind power capacity from GENERATION RESOURCES, 2019 the current negligible levels to around 1,000 MW by 2020 and about 6,200 MW by 2030. The aim is to increase the proportion of electricity production from wind power from 0.7% in 2020 to 2.4% by 2030. Linked to the development of renewable energy sources (in particular wind power capacity) the sys- tem level benefits can be split into the three catego- ries as proposed in paragraph ‘D.2’. E.5.1 Optimized energy generation mix The replacement of conventional power plants with wind generation (as well as other alternative ener- gies) to supply an ever-growing demand entails dif- ferent investment strategies for the construction and operations of new power plants. The leveled cost of energy (“LCOE”) is a possible mechanism for esti- mating the size of the investment required. LCOE is often cited as a convenient summary yard- stick of the overall competiveness of different gen- Source: Energy Information Administration, 2014, (5) erating technologies. It represents the energy cost of building and operating a generating plant over an assumed life and duty cycle. Key inputs to calculat- ing LCOE include capital costs, fuel costs, fixed and variable operations and maintenance (O&M) costs, FIGURE 89: LEVELIZED COST OF ELECTRICITY (LCOE) FOR NEW financing costs and an assumed utilization rate for GENERATION RESOURCES, 2040 each plant type. In order to assign a financial value for the annual ben- efits related to the optimization of the generation mix it is preferable to start from a forecast of the LCOE values over at least two time periods (mid-term and long-term) because this parameter can change signif- icantly over time for some generating technologies. A credible international source like the U.S. Energy Information Administration (EIA) was considered as a source to capture the variability of the stabilized cost of new generation resources predicted in 2019 (Figure 88) and 2040 (Figure 89). These forecasted figures are available from the annual energy outlook 2014. Considering the current energy mix of Vietnam’s power generation profile, the gas-fired power plants and conventional fossil-fuel plants are considered candidates for replacement with wind generation because of their predicted costs. The benefits of wind generation would still be a net positive if an Source: Energy Information Administration, 2014, (5) LCOE of $ 100/MWh is considered because Vietnam Volume 2: Cost-Benefit Analysis 171 will likely require gas to be imported at higher costs than Table 29 shows the annual reduction of fuel consump- reported by EIA. tion based on the wind penetration assumptions shared with NPT/NLDC. This benefit has already been monetized The LCOE of conventional generation systems has in the estimated reduction of generation cost, as it is been estimated using a conservative approach. In fact included in the calculation of the LCOE parameter. Nev- the average LCOE of the combined cycle and the con- ertheless it is an important factor for the evaluation of the ventional coal power plant has been assumed in order impact of new renewable generation and for the energy to quantify the total reduction of the generation costs strategy of Vietnam. achievable with the implementation of new wind capac- ity in the Vietnamese network. This calculation has been performed for each year of the time horizon starting from E.5.3 Reduced GHG emissions the wind penetration timeline assumption shared with The reduced Natural gas power requirement caused by Vietnamese stakeholders. The total nominal reduction of using wind generation instead determines the reduction the generation cost is $873,000,000 at the end of the of GHG emissions. For this calculation the average CO2 analyzed period (15th year) as shown in Table 28 and cor- emission of 0.416 ton/MWh for gas-fired generation is responds to $305,000,000 discounted to 2015. assumed (typical average value of new combined cycle and new open cycle gas turbine). E.5.2 Increased fuel availability In order to assess the financial value of this benefit a conser- The reduced fuel consumption has been based on the vative value of 10$/ton for CO2 emission has been assumed. reduced Natural gas power capacity substituted by wind generation and assumes that an average amount of fuel Table 30 shows the annual financial value of CO2 emis- needed to produce one MWh of energy is equal to 7 .03 sion savings, which determines a total nominal benefit MBTU (typical average value of new combined cycle and equal to $346,000,000 in the analyzed period and cor- new open cycle gas turbine). responds to $128,000,000 discounted to 2015. TABLE 28: REDUCTION OF ENERGY GENERATION COST DUE TO THE INTEGRATION OF WIND GENERATION ENABLED BY THE SMART GRID ROADMAP Wind energy Average LCOE Yearly generation Wind Capacity generation Gas-fired Power LCOE Wind [$/ LCOE difference cost reduction Year installed [MW] [TWh] (a) Plants [$/MWh] (b) MWh] (c) [$/MWh] (d=b-c) [M$] (a∙d) 2015 0 0 80.8 80.3 0.5 0 2016 200 0.4 80.8 80.3 0.5 0 2017 400 0.8 80.8 80.3 0.5 0 2018 600 1.2 80.8 80.3 0.5 1 2019 800 1.6 80.8 80.3 0.5 1 2020 1,000 2 84.1 73.1 11 22 2021 1,520 3.04 84.1 73.1 11 33 2022 2,040 4.08 84.1 73.1 11 45 2023 2,560 5.12 84.1 73.1 11 56 2024 3,080 6.16 84.1 73.1 11 68 2025 3,600 7.2 84.1 73.1 11 79 2026 4,120 8.24 84.1 73.1 11 91 2027 4,640 9.28 84.1 73.1 11 102 2028 5,160 10.32 84.1 73.1 11 114 2029 5,680 11.36 84.1 73.1 11 125 2030 6,200 12.4 84.1 73.1 11 136 TOTAL Generation cost 873 reduction [M$]: Source: Authors 172 Smart Grid to Enhance Power Transmission in Vietnam TABLE 29: REDUCTION FUEL CONSUMPTION DUE TO THE INTEGRATION OF WIND GENERATION ENABLED BY THE SMART GRID ROADMAP Average fuel consumption Average fuel consumption Wind Capacity Wind energy generation of gas-fired generation of gas-fired generation Year installed [MW] [TWh] (a) [MBTU/MWh] (b) [106 MBTU] (c=a∙b) 2015 0 0.0 7.03 0.0 2016 200 0.4 7.03 2.8 2017 400 0.8 7.03 5.6 2018 600 1.2 7.03 8.4 2019 800 1.6 7.03 11.2 2020 1,000 2.0 7.03 14.1 2021 1,520 3.0 7.03 21.4 2022 2,040 4.1 7.03 28.7 2023 2,560 5.1 7.03 36.0 2024 3,080 6.2 7.03 43.3 2025 3,600 7.2 7.03 50.6 2026 4,120 8.2 7.03 57.9 2027 4,640 9.3 7.03 65.2 2028 5,160 10.3 7.03 72.5 2029 5,680 11.4 7.03 79.9 2030 6,200 12.4 7.03 87.2 TOTAL fuel savings [106 585 MBTU]: Source: Authors TABLE 30: REDUCTION GHG DUE TO THE INTEGRATION OF WIND GENERATION ENABLED BY THE SMART GRID ROADMAP Average CO2 Average CO2 Wind energy emission rate of emission of gas- CO2 emission Wind Capacity generation gas-fired generation fired generation monetization CO2 emission Year installed [MW] [TWh] (a) [tons/MWh] (b) [Mtons] (c=a∙b) [$/ton] (d) savings [M$] (c∙d) 2015 0 0.0 0.416 0.0 10.0 0.0 2016 200 0.4 0.416 0.2 10.0 1.7 2017 400 0.8 0.416 0.3 10.0 3.3 2018 600 1.2 0.416 0.5 10.0 5.0 2019 800 1.6 0.416 0.7 10.0 6.7 2020 1,000 2.0 0.416 0.8 10.0 8.3 2021 1,520 3.0 0.416 1.3 10.0 12.6 2022 2,040 4.1 0.416 1.7 10.0 17.0 2023 2,560 5.1 0.416 2.1 10.0 21.3 2024 3,080 6.2 0.416 2.6 10.0 25.6 2025 3,600 7.2 0.416 3.0 10.0 30.0 2026 4,120 8.2 0.416 3.4 10.0 34.3 2027 4,640 9.3 0.416 3.9 10.0 38.6 2028 5,160 10.3 0.416 4.3 10.0 42.9 2029 5,680 11.4 0.416 4.7 10.0 47.3 2030 6,200 12.4 0.416 5.2 10.0 51.6 TOTAL CO2 emission savings 346 [M$]: Source: Authors Volume 2: Cost-Benefit Analysis 173 E.6 Integration of Renewable energy real-time monitoring and analysis, which precludes generation potential stability problems. As renewable penetration increases, power systems will be more responsive when International experience demonstrates that an inad- dealing with sudden changes and the potential stability equate network infrastructure is a significant barrier to issues. efficient utilization of available production from variable renewable energy and as a consequence can be an Another benefit to be considered in this assessment is obstacle to the investments in new RES generation. the ability to avoid having to curtail RES generation. Just as WAMS, SAS, SVC, LLS, PQ and FLS can help with “the Smart Grid solutions can facilitate the integration of RES reduction of energy not served“ , they could also elimi- whilst limiting the need for additional infrastructure and nate the need to reduce renewable energy that cannot improving system operations. Table 31 shows the bene- be generated for want of the system’s ability to manage fits obtained by implementing each project and lists them the additional load. in order of merit in terms of their potential for enabling RES generation. DGA and GIS do not have a significant impact on RES investment decisions. The HVDC technology and the Dynamic Thermal Circuit Rating are perhaps the most versatile of the Smart Grid initiatives in terms of integrating new variable renew- E.7 Assumptions on blackout able generation. In fact the increased transfer capacity prevention is a fundamental benefit, which will facilitate the instal- lation of wind or solar power plants carrying the gener- The information collected during the discovery process ated energy to the load areas. HVDC can also balance reveals that Vietnamese customers suffer a number of the natural fluctuation of renewables thanks to the active power outages, each of a considerable average dura- power control, which is an inherent advantage for sup- tion [20]. Amortizing the numbers across the popula- porting variable generation. tion gives a total of 28 interruptions per customer, per year, with each one lasting 2 hours and 40 minutes. The WAMS can be an important enabling technology for total elapsed time that an average customer suffers a a large-scale variable RES installation thanks to the power outage in Vietnam is 4,461 minutes per year, or 74 TABLE 31: EFFECTS OF THE SMART GRID APPLICATIONS ON RENEWABLE GENERATION INTEGRATION MERIT ORDER SMART GRID APPLICATION EFFECTS ON RENEWABLE GENERATION INTEGRATION Increased transfer capacity 1 HVDC Active power control 2 DTCR Increased transfer capacity Stability issues avoided SVC Reduced RES curtailment 3 Stability issues avoided WAMS Reduced RES curtailment SAS Reduced RES curtailment LLS Reduced RES curtailment 4 PQ & Metering Reduced RES curtailment FLS Reduced RES curtailment DGA Negligible 5 GIS Negligible Source: Authors 174 Smart Grid to Enhance Power Transmission in Vietnam hours. Comparing these figures with mature economies The analysis suggests that Smart Grid technologies can highlights that the average Vietnamese customer expe- avoid at least one major event such as the one in 2013, riences 14 times more interruptions than a European cus- which seems to occur every 8 years. Allowing for the tomer and for nearly 40 times as long. time taken to achieve the full rollout of the relevant Smart Grid technology it is likely that over the next 15 years it This data and the information collected during the dis- will be possible to prevent 4 major blackouts. Table 32 covery process reveals that brownouts (or partial black- shows the total interruption cost reduction due to black- outs) are a very serious problem in Vietnam [24] and outs prevented, which the Smart Grid technology will such events hit firms hard reducing their ability to attract make possible. This is a reasonable assumption given investments [4] [25]. For business users these interrup- that, according to ENV [30], there were 18 Power Sys- tions amount to 10% of the Peak Demand for 30 minutes tem Collapses that occurred between 1995 and 2006. a year, which is pretty conservative given the average pri- There were also several others brownout events in the vate Vietnamese citizen’s experience. following 7 years (including the 2013 blackout). These outages occurred 8 times in the Northern Power System Nevertheless, the prevention of the frequency of major and 9 times in the Southern Power System. The Northern events like blackouts has not been introduced in the eco- and the Southern power generation systems contribute nomic indicators or in the evaluation. 41% and 49% respectively to the total load. The potential total cost reduction of reduced or prevented outages is During May 2013 the southern region of Vietnam expe- estimated at $644,000,000, which corresponds to a dis- rienced a massive power outage that lasted for some counted value of $275,000,000 for 2015. hours. This was caused by a truck that, while delivering a tree, damaged a line in the national power grid (500 KV) The benefit calculated above by avoiding 4 major events in New Bình Du’o’ng City urban area. The transmission is quite conservative considering that the cost of a sin- system was not compliant with the N-1 security crite- gle blackout has an estimated value in the billions. This rion, so the truck incident led to a cascade effect causing reduction/prevention together with the system level ben- a wide ranging blackout across twenty two provinces. efits will make a significant difference to the economic This is a typical case where a small incident has a major indicators. knock-on effect causing significant damage. The different Smart Grid solutions together provide the Blackout prevention is achievable with the deployment of means of reducing or entirely preventing outages. Table Smart Grid technology [26] [27] [28]. In fact blackout pre- 33 shows the contribution from each project and priori- vention was one the main drivers that pushed the devel- tizes them according to the level of impact they will have opment of Smart Grids technologies in USA, Europe and on blackout mitigation/prevention. around the world. The Guidebook of the Cost/Benefit Analy- sis of EPRI’s Smart Grid Demonstration TABLE 32: REDUCTION OF INTERRUPTION COST DUE TO BLACKOUT Projects examines the benefits and costs REDUCTION ENABLED BY THE SMART GRID SOLUTIONS of avoiding major power interruption [29]. The fast growth in demand as well as the Interruption Yearly interruption Year ENS [MW] cost [M$] cost reduction [M$] rapid power network development seems to be affecting the South of Vietnam far 2017 40,021 83 83 more than the north, in fact to the extent of 49% of the total load [12] with an aver- 2021 58,594 122 122 age duration of 3 hours. 2025 85,788 178 178 The main reason for introducing the Smart 2029 125,602 261 261 Grid technologies is to reduce the fre- quency of these major events which are TOTAL interruption cost reduction causing huge economic losses and affect- 644 due to avoided ing the credibility of the network opera- blackouts [M$]: tors and impacting the country’s potential for attracting investments. Source: Authors Volume 2: Cost-Benefit Analysis 175 TABLE 33: EFFECTS OF THE SMART GRID APPLICATIONS E.8 Summary of the Benefits ON BLACKOUT PREVENTION The benefits calculated are at the individual level consid- ering each Smart Grid application and provide an overall MERIT SMART GRID CONTRIBUTION FOR systemic level view. ORDER APPLICATION BLACKOUT PREVENTION WAMS The financial valuation of the system level benefits has Increased network not been factored into the economic indicators in the 1 HVDC stability interests of taking a conservative view. This deliberate SVC underestimation has also been extended to the eco- DTCR nomic indicators for the individual Smart Grid applica- tions. However, they have been quantified for the whole SAS Increased efficiency in Smart Grid roadmap implementation. 2 LLS system operation A summary of all the benefits calculated is presented in FLS Table 34 and in Figure 90. PQ & Metering The system evaluation highlights how the investments 3 DGA Negligible in developing a certain number of Smart Grid solutions GIS (viable for Vietnam) allow building a “Smart” transmis- sion network and enhancing electrical system reliability. Source: Authors TABLE 34: SUMMARY OF THE BENEFITS Benefit Discounted Benefit Value (2015 $) Comment Factored in to calculations for the economic Individual SG Initiatives $586,217,918 indicators Integration of Wind Generation and $305,000,000 Increased Fuel Availability Not factored in to calculations for the economic Reduced GHG emissions $128,000,000 indicators Blackout Prevention $275,000,000 Source: Authors FIGURE 90: SUMMARY OF THE BENEFITS Source: Authors F. Identify and Quantify Costs F.1 Key Points Summary F.2 Substation Automation System (SAS) This chapter describes all the assumptions related to the costs necessary for the implementation of the Smart Investment cost for the implementation of the SAS in Grid solutions. existing substation (Table 36) is included in the NPT pre- sentation: “Key efficiency and reliability challenges for The costs are reported in terms of capital expenditures NPT and current Smart Grid modernization opportunities (CAPEX) and operating expenditures needed to operate . In the presentation two different costs are and priorities” the systems (OPEX). The nominal and discounted values considered for retrofitting 500 kV substations and 220 kV of such costs amortized over the time horizon are sum- substations. marized in Table 35. TABLE 35: SUMMARY OF COSTS OF SMART GRID INITIATIVES Initiative Nominal Costs Discounted Costs Scale of operation CAPEX: $226,200,000 CAPEX: $147,903,537 18 retrofitted substations SAS OPEX: $25,205,250 OPEX: $10,854,340 150 new SAS CAPEX: $1,792,000 CAPEX: $1,268,311 224 PMUs installed at 500 kV and 220 kV WAMS OPEX: $214,840 OPEX: $96,615 voltage level CAPEX: $1,668,000 CAPEX: $1,431,404 20 detectors monitoring lightning activity Lightning Location System OPEX: $899,000 OPEX: $443,395 across Vietnam CAPEX: $31,500,000 CAPEX: $24,962,690 900 Mvar SVCs installed in the most critical SVC OPEX: $1,255,500 OPEX: $588,058 area of Vietnam in terms of voltage control CAPEX: ($16,800,000) CAPEX: ($13,313,434) 2,000 MW interconnection, 800 km length, HVDC OPEX: $118,098,000 OPEX: $55,315,436 using DC instead of AC technology CAPEX: $8,400,000 CAPEX: $7,289,256 140 Fault locators FLS OPEX: Negligible OPEX: Negligible CAPEX: $77,592,000 CAPEX: $41,696,690 732 transformers equipped, (all existing and DGA OPEX: $3,343,245 OPEX: $1,364,572 new) Dynamic Thermal CAPEX: $1 280 000 CAPEX: $1,110,743 40 sensors monitoring 400 km lines Circuit Rating OPEX: $371 200 OPEX: $183,079 CAPEX: $175,000 CAPEX: $159,090 Geographic information of power system GIS OPEX: $262,500 OPEX: $133,106 components across Vietnam Power quality monitoring CAPEX: $301,500 CAPEX: $241,648 105 power quality measurement devices at and Metering Data OPEX: $97,214 OPEX: $45,962 500 kV and 220 kV voltage level Acquisition Systems Source: Authors 176 Volume 2: Cost-Benefit Analysis 177 TABLE 36: CAPEX OF SUBSTATION AUTOMATION SYSTEM ADOPTED IN THE BUSINESS CASE Quantity over time horizon (a) Cost per unit [$] (b) Total cost [$] (a∙b) Source 500 kV substations retrofitting 5 2,400,000 12,000,000 NPT 220 kV substations retrofitting 13 900,000 11,700,000 NPT CAPEX 500 kV new substations 45 2,400,000 108,000,000 NPT 220 kV new substations 105 900,000 94,500,000 NPT Source: Authors TABLE 37: OPEX OF SUBSTATION AUTOMATION SYSTEM ADOPTED IN THE BUSINESS CASE Total Yearly Cost [$] Source 500 kV substations retrofitting 24,000 CESI 220 kV substations retrofitting 9,000 CESI OPEX 500 kV new substations 24,000 CESI 220 kV new substations 9,000 CESI Source: Authors In the Business Case the cost for the implementation of F.3 Wide Area Monitoring System SAS equipment in new substations has been assumed (WAMS) to be the same as the retrofitting an existing substation6. The cost of a single Phase Measurement Unit (PMU) has It is assumed that all new substations installed from been provided by NPT. 2016 will be equipped with SAS. The NPT forecast indi- cates the number of new substations. In the business case it has been assumed that PMUs will be installed in all the existing and planned substations for OPEX estimates in Table 37 are based on 1% of capital both the 500 kV and 220 kV networks (Table 38). expenditure and correspond to the full implementation of the SAS in existing and planned substations. TABLE 38: CAPEX OF WIDE AREA MONITORING SYSTEM ADOPTED IN THE BUSINESS CASE Quantity over Cost per unit Total cost time horizon (a) [$] (b) [$] (a∙b) Source PMU installation 500 and Cost per unit source: NPT, 74 8,000a 592,000 220 kV existing substations Quantity assumption: CESI CAPEX PMU installation 500 and Cost per unit source: NPT, 150 8,000 1,200,000 220 kV new substations Quantity assumption: CESI Source: Authors a. The source of the WAMS prices is the Investment Management Department—EVN NPT—and is related to already installed PMU cost. 178 Smart Grid to Enhance Power Transmission in Vietnam TABLE 39: OPEX OF WIDE AREA MONITORING SYSTEM ADOPTED IN THE BUSINESS CASE Total Yearly Cost [$] Source PMU installation 500 and 220 kV existing substations 5,920 CESI OPEX PMU installation 500 and 220 kV new substations 12,000 CESI Source: Authors OPEX estimates in Table 39 are based on 1% of capital Civil works (Table 40) and site rental (Table 41) will vary expenditures and correspond to the full implementation depending on the installation sites (an average value has of the PMUs in existing and planned substations. been considered). Data analysis operational cost has been estimated based F.4 Lightning Location System (LLS) on 48 man-months per year for the analysis team at an estimated cost of $500/month. CAPEX for the Lightning Location System will vary as a function of the number of lightning detectors installed. Site rental and electricity supply depend on the number The number of detectors indicated in Table 40 (approxi- of lightning detectors installed, while other OPEX (Data mately 20) is considered the minimum amount needed analysis, hardware and software operations and mainte- to provide a reliable and useful lightning monitoring sys- nance) are not included in these calculations. tem based on the geography of Vietnam. It is important to highlight that one of the main character- F.5 Static Var Compensator (SVC) istics of this Smart Grid initiative is its capability in driving the Transmission Surge Line Arresters (TLSA) installation. The Cost per Mvar of Static Var Compensator has been The investment in purchasing TLSAs is not considered in supplied by manufacturers. this analysis because it has been assumed that NPT has however to install such devices, independently from the Total SVC capacity installed (900 Mvar) has been esti- development of a Lightning Location System. mated by CESI based on an estimate of 20% of the total TABLE 40: CAPEX OF LIGHTNING LOCATION SYSTEM ADOPTED IN THE BUSINESS CASE Quantity over Cost per unit Total cost Source time horizon (a) [$] (b) [$] (a∙b) Lightning detectors 20 54,000 1,080,000 CESI Civil works 20 10,000 200,000 CESI Telecommunication between detectors and control center, data collection and 1 30,000 30,000 CESI CAPEX management (ADSL, Routers, DB’s) Lightning Location Central Analyzer software 1 172,000 172,000 CESI CESI/ Archiving and handling of Lightning data 1 186,000 186,000 Service software provider Source: Authors Volume 2: Cost-Benefit Analysis 179 TABLE 41: OPEX OF LIGHTNING LOCATION SYSTEM ADOPTED IN THE BUSINESS CASE Total cost [$] (a∙b) Source Site rental 10,000 CESI Electricity supply 4,000 CESI OPEX Data analysis 24,000 CESI Hardware and software operation and maintenance 24,000 CESI Source: Authors reactive power regulation capacity. The basis for this esti- Re-locatable SVCs can be moved around to different parts mate is as follows: of the grid depending on the dynamic operational require- ments of a rapidly changing topology. The average cost of a. The SVC capacity in the United Kingdom is 30% a large sized SVC installation including dedicated trans- of the total reactive power regulation capacity; formers and feeders has been in the range of $35,000- $55,000 [31] per Mvar in the past years. The installation b. The installation of Static Var Compensators in of the SVC in the tertiary winding of an existing trans- Vietnam will be limited to those areas most former can reduce this cost by as much as 30%. Furthermore affected by voltage stability issues. SVC instal- the information collected from manufacturers shows how lation will very likely be confined to the central the cost is shrinking thanks to the economy of scale due to area of Vietnam which is characterized by a lack of the wider take-up of this relatively new technology. generation capacity and long transmission lines carrying the energy generated in the north of the Given that the SVCs currently installed in Vietnam do not country to the southern region where there is a have dedicated transformers, a similar configuration has higher demand. been assumed for new installs thus a conservative cost The cost per Mvar refers to the re-locatable technology, of $35,000 for the installation of the Static Var Compen- which has higher costs than for fixed units but allows sator has been adopted (based on $30,000 per Mvar for much greater flexibility in the choice of ad hoc locations. the system and $5,000 per Mvar for the civil works). TABLE 42: CAPEX OF STATIC VAR COMPENSATORS ADOPTED IN THE BUSINESS CASE Capacity installed over Cost per Mvar Total cost time horizon [Mvar] (a) [$/Mvar] (b) [$] (a∙b) Source Capacity installed Static Var Compensator 900 30,000 27,000,000 source: CESI; Cost CAPEX (re-locatable) source: manufacturers Civil works 900 5,000 4,500,000 CESI Source: Authors TABLE 43: OPEX OF STATIC VAR COMPENSATORS ADOPTED IN THE BUSINESS CASE Total Yearly Cost [$] Source Preventive maintenance (3 days/year) + On-line support 60,000 CESI OPEX Corrective maintenance 30,000 CESI Spares e consumables 3,000 CESI Source: Authors 180 Smart Grid to Enhance Power Transmission in Vietnam F.6 High Voltage Direct Current e. The average cost of the right of way is $10 per (HVDC) technology square meter, which makes HVDC a much more economical option; The incremental cost of a new 800 km DC link as opposed f. The additional equipment required for AC trans- to an AC solution has been estimated in order to assess mission (substations, feeders, FACTS) is 10% of the economic feasibility of HVDC technology. the total cost of the lines; and The costs (reported in Table 44) have been calculated g. The cost of the lines includes the engineering, based on the following hypotheses for the HVDC link: procurement and construction costs and the esti- mations take into account the localizing factor. a. Bipolar +/- 500 kV Overhead line; It is possible to calculate the total CAPEX of the HVAC b. Rated power: 2,000 MW; and HVDC interconnections from the details in Table 44: c. Four sub-conductors per pole; and a. HVAC: $692,800,000; d. VSC technology for the converter stations. b. HVDC: $676,000,000. Other assumptions for the incremental cost calculation are the following: Therefore, the use of HVDC technology determines a CAPEX saving of $16,800,000. a. 500 kV and 2,000 MW rated power for both AC solution; The OPEX shown in Table 45 has been estimated at 1.5% of CAPEX for the HVDC and HVAC transmission lines and b. AC and HVDC lines have the same length; 3% of CAPEX for the converter stations. c. The sizing of the conductors is optimized separately for AC and HVDC. The sizing of the section is made by an optimization which is aimed to match the F.7 Fault Locator System (FLS) investment cost of the line and the cost of losses over 15 years (optimum conductors to minimize For the Fault Locator System only the cost of the equip- investment plus capitalized cost of losses); ment has been considered (Table 46). Other investment and operational costs have been disregarded. d. HVDC transmission lines require 25 meters less right of way than HVAC; TABLE 44: CAPEX OF HIGH VOLTAGE DIRECT CURRENT TECHNOLOGY ADOPTED IN THE BUSINESS CASE Cost per unit ([$/ km] for the line, Quantity (a) [$] for others) (b) Total cost [$] (a∙b) Source HVDC Overhead lines engineering, 800 km 345,000 276,000,000 CESI procurement and construction HVDC Converter stations 2 200,000,000 400,000,000 Manufacturers HVAC Overhead lines engineering, procurement and construction (Avoided 800 km -560,000 -448,000,000 CESI CAPEX CAPEX) HVAC Cost of additional equipment (Substations, feeders, Facts, ...) (Avoided 1 -44,800,000 -44,800,000 CESI CAPEX) HVAC additional right of way cost 1 -200,000,000 -200 000,000 CESI (Avoided CAPEX) Source: Authors Volume 2: Cost-Benefit Analysis 181 TABLE 45: OPEX OF HIGH VOLTAGE DIRECT CURRENT TECHNOLOGY ADOPTED IN THE BUSINESS CASE Total Yearly Cost [$] Source HVDC OHL O&M 4,140,000 CESI OPEX HVDC O&M Converter stations 12,000,000 CESI HVAC OHL O&M (Avoided OPEX) -7,392,000 CESI Source: Authors TABLE 46: CAPEX OF FAULT LOCATOR SYSTEM ADOPTED IN THE BUSINESS CASE Quantity over time horizon (a) Cost per unit [$] (b) Total cost [$] (a∙b) Source CAPEX Equipment 140 60,000 8,400,000 NPT Source: Authors F.8 On-line Dissolved Gas-in-oil NPT forecasts 68,100 MVA new 500 kV transformer Analysis (DGA) capacity and 139,952 MVA new 220 kV transformer capacity in the 2015-2030 period. Assuming 525 MVA as The Business Case assumes that only transformers a reference size of the 500 kV transformers and 250 MVA installed after 2015 will be equipped with Dissolved Gas- for the 220 kV transformers, the number of sensors is esti- in-oil sensors. mated at 690. All the existing 500 kV transformers are assumed to be equipped with the sensors i.e. a total of The number of new transformers anticipated over the 42 sensors. The CAPEX evaluation is shown in Table 47 . time horizon has been estimated on the basis of the new transformer capacity forecast by NPT. The OPEX costs shown in Table 48 are estimated at 0.5% of capital expenditures for every year. TABLE 47: CAPEX OF ON-LINE DISSOLVED GAS-IN-OIL ANALYSIS ADOPTED IN THE BUSINESS CASE Quantity over Cost per unit Total cost time horizon (a) [$] (b) [$] (a∙b) Source Sensors on existing Cost per unit source: NPT, Quantity assumption: 42 106,000 4,452,000 transformers CESI (elaboration on NPT documentation) CAPEX Sensors on new Cost per unit source: NPT, Quantity assumption: 690 106,000 73,140,000 transformers CESI (elaboration on NPT documentation) Source: Authors TABLE 48: OPEX OF ON-LINE DISSOLVED GAS-IN-OIL ANALYSIS ADOPTED IN THE BUSINESS CASE Total Yearly Cost [$] Source OPEX O&M DGA new transformers 373,650 CESI Source: Authors 182 Smart Grid to Enhance Power Transmission in Vietnam TABLE 49: CAPEX OF DYNAMIC THERMAL CIRCUIT RATING ADOPTED IN THE BUSINESS CASE Quantity over Cost per unit Total cost time horizon (a) [$] (b) [$] (a∙b) Source Cost per unit source: manufacturer, CAPEX Sensors 40 32,000 1,280,000 Quantity assumption: CESI Source: Authors TABLE 50: OPEX OF DYNAMIC THERMAL CIRCUIT RATING ADOPTED IN THE BUSINESS CASE Total Yearly Cost [$] Source OPEX O&M DTCR 25,600 CESI Source: Authors F.9 Dynamic Thermal Circuit Rating F.10 Geographic Information Systems (DTCR) (GIS) The number of sensors to be deployed has been esti- GIS costs are mainly related to the development of the mated at one sensor every 10 km of line length. In the software and user interfaces, which will facilitate better business case four lines of 100 km length are equipped operational control and management of network automa- with sensors, therefore the total amount of sensors tion. Table 51 shows the costs assumed for the technol- required is 40 (see Table 49). ogy and includes hardware. OPEX reported in Table 50 have been calculated consid- The OPEX costs shown in Table 52 are estimated at 10% ering 2% of CAPEX for every year. of CAPEX for every year. TABLE 51: CAPEX OF GEOGRAPHIC INFORMATION SYSTEM ADOPTED IN THE BUSINESS CASE Quantity over time horizon (a) Cost per unit [$] (b) Total cost [$] (a∙b) Source Software applications 1 150,000 150,000 CESI CAPEX Hardware equipment 1 25,000 25,000 CESI Source: Authors TABLE 52: OPEX OF GEOGRAPHIC INFORMATION SYSTEM ADOPTED IN THE BUSINESS CASE Total Yearly Cost [$] Source OPEX Hardware and software maintenance 17,500 CESI Source: Authors Volume 2: Cost-Benefit Analysis 183 F.11 Power Quality monitoring and installation of the devices is aligned with the installation Metering Data Acquisition of new substations. Systems The equipment installed in order to carry out Power Qual- ity monitoring can also be used by the Metering and Data It has been assumed that thirty percent of the substa- Acquisition system. tions will be equipped with power quality analyzers in order to facilitate complete and effective monitoring. Data analysis is based on an estimated 3 man-months The number reported in Table 53 (105 analyzers) refers per year for the analysis team at a cost of 500 $/month to the total installed over the time horizon. In fact the (Table 54). TABLE 53: CAPEX OF POWER QUALITY MONITORING AND METERING DATA ACQUISITION SYSTEMS ADOPTED IN THE BUSINESS CASE Quantity over Cost per Total cost Source time horizon (a) unit [$] (b) [$] (a∙b) Cost per unit source: manufacturer, Equipment 105 2,300 241,500 Quantity assumption: CESI CAPEX Software license and hardware Cost per unit source: manufacturer/ 1 60,000 60,000 in the control center provider, Quantity assumption: CESI Source: Authors TABLE 54: OPEX OF POWER QUALITY MONITORING AND METERING DATA ACQUISITION SYSTEMS ADOPTED IN THE BUSINESS CASE Total Yearly Cost [$] Source O&M control center + software updates 6,000 Manufacturer/provider OPEX Data analysis 1,500 CESI Source: Authors G. Compare Costs and Benefits G.1 Key Points Summary compounded return rate” (or rate of return) that makes the Net Present Value of all cash flows This chapter aims to compare costs and benefits for all (both positive and negative) of a particular invest- the Smart Grid solutions in order to get a reliable estima- ment equal to zero; tion of their economic KPIs. c. B/C ratio: The Benefits-Costs ratio summarizes the overall value for money of a project and it is It is important to stress that these values and indicators calculated as the ratio of the discounted present are very conservative. This is because the system level values of benefits and the discounted present val- discounted benefits derived from the optimized energy ues of costs; mix and increased fuel availability ($305,000,000), reduced GHG emission ($128,000,000) as well as the pre- d. Switching value: This is the value that an esti- vention of major blackout events ($275,000,000) were not mated benefit must achieve in order to equal zero internalized in the economic indicators (NPV, EIRR and B/C NPV. The assumption is chosen specifically for ration). This deliberate underestimation makes the case each Smart Grid initiative considering both the for the Smart Grid technologies all the more compelling. uncertainty of its estimation and the impact on the economic benefits of the project. It is impor- A table is presented in the following paragraphs for each tant to underline that the Transmission OPEX Smart Grid initiative. In the top part it reports four param- reduction benefit, if present, is considered equal eters which are the synthetic values (KPIs) of the direct to zero in the breakeven calculation (conservative financial benefits of the project: approach). a. Total NPV 2030: The Net Present Value repre- The lower part of the table is where the benefits and sents the discounted cash flows, i.e. the present costs (identified respectively in chapters ‘E’ and ‘F’) are value of future (up to 2030) cash flows; detailed. b. EIRR: The Economic Internal Rate of Return on an Table 55 summarizes the synthetic values of the eco- investment or project is the “annualized effective nomic benefits of each Smart Grid initiative. TABLE 55: SUMMARY OF THE SYNTHETIC VALUES OF THE ECONOMIC BENEFITS OF SMART GRID INITIATIVES Initiative Results • Total NPV: $179,002,262 • EIRR: 41% SAS • B/C ratio: 2.13 • Switching value: Avoided ENS per SAS = 75.9 MWh/year (assuming Transmission OPEX reduction benefit equal to zero) • Total NPV: $22,951,362 • EIRR: 204% WAMS • B/C ratio: 17.82 • Switching value: Percentage of events prevented = 4.94% (assuming Transmission OPEX reduction benefit equal to zero) • Total NPV: $11,035,144 • EIRR: 164% Lightning Location • B/C ratio: 6.89 System • Switching value: Percentage of events prevented = 21.3% (assuming Transmission OPEX reduction benefit equal to zero). (Continued next page) 184 Volume 2: Cost-Benefit Analysis 185 55:(CONTINUED) TABLE 55 SUMMARY OF THE SYNTHETIC VALUES OF THE ECONOMIC BENEFITS OF SMART GRID INITIATIVES Initiative Results • Total NPV: $5,265,412 • EIRR: 14% SVC • B/C ratio: 1.21 • Switching value: Percentage of events prevented = 60.3% (assuming Transmission OPEX reduction benefit equal to zero) • Total NPV: $23,524,111 • EIRR: All positive cash flows HVDC • B/C ratio: 1.56 • Switching value: Line length = 773 km (assuming Transmission OPEX reduction benefit equal to zero) • Total NPV: $1,235,045 • EIRR: 13% FLS • B/C ratio: 1.17 • Switching value: % monitored lines with faults = 64.1% • Total NPV: $5,532,566 • EIRR: 12% DGA • B/C ratio: 1.13 • Switching value: Average cost of a transformer fault = $7,907. • Total NPV: $44,132,102 • EIRR: All positive cash flows Dynamic Thermal • B/C ratio: 35.11 Circuit Rating • Switching value: Line reconductoring investment deferment = 0.18 years (assuming Transmission OPEX reduction benefit equal to zero) • Total NPV: $762,214 • EIRR: 48% GIS • B/C ratio: 3.61 • Switching value: % reduction of SAS O&M = 2.7% • Total NPV: $11,003,193 Power quality • EIRR: 797% monitoring and • B/C ratio: 39.26 Metering Data • Switching value: Percentage of events prevented = 10.0% (assuming Transmission OPEX reduction Acquisition Systems benefit equal to zero) Source: Authors G.2 Substation Automation System G.3 Wide Area Monitoring System (SAS) (WAMS) Table 56 shows that the costs are spread over a num- Table 57 shows that the major costs are concentrated ber of years and that over the same period the benefits in the first few years because of the huge implementa- increase because of the cumulative effects of old and tion costs for the existing substations in the network. The new installed SAS. Maximum yearly value of costs is benefits increase over the same period because of the $34,000,000 in the first year of investment, while maxi- cumulative effects of old and new installed PMUs. Maxi- mum yearly value of benefits of $69,000,000 occurs in mum annual value of costs is $436,560, which occurs in the last few years of the timeline. the second year of investment; while maximum yearly value of benefits is $5,068,651 occur in the last few years of the timeline. The picture can't be display ed.     CESI  186   COST‐BENEFIT ANALYSIS    B5013477   G.2  Substation Automation System (SAS)  246.  Table 56 shows that the costs are spread over a number of years and that over the same period the benefits increase because of the cumulative effects of  old  and  new  installed  SAS.  Maximum  yearly  value  of  costs  is  $34,000,000  in  the  first  year  of  investment,  while  maximum  yearly  value  of  benefits  of  $69,000,000 occurs in the last few years of the timeline.  TABLE   56: SAS COSTS AND BENEFITS COMPARISON Table 56: SAS costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 179 002 262 EIRR 41% B/C ratio 2.13 Avoided ENS per SAS to break-even (considering Transmission 75.9 OPEX reduction benefit equal to zero) [MWh/year] unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 0 26 850 000 34 500 000 39 450 000 44 400 000 49 350 000 53 400 000 57 450 000 61 500 000 65 550 000 69 600 000 69 600 000 69 600 000 69 600 000 69 600 000 a. Direct Transmission OPEX reduction (automation and USD 0 0 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced frequency and USD 0 0 7 650 000 15 300 000 20 250 000 25 200 000 30 150 000 34 200 000 38 250 000 42 300 000 46 350 000 50 400 000 50 400 000 50 400 000 50 400 000 50 400 000 duration of system faults e. Avoided CAPEX and Deferred Capacity Investments USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Costs USD 0 34 466 250 34 807 500 23 180 250 23 403 000 23 625 750 19 758 000 19 940 250 20 122 500 20 304 750 20 487 000 2 262 000 2 262 000 2 262 000 2 262 000 2 262 000 Total Costs Capex USD 0 34 125 000 34 125 000 22 275 000 22 275 000 22 275 000 18 225 000 18 225 000 18 225 000 18 225 000 18 225 000 0 0 0 0 0 Smart Grid to Enhance Power Transmission in Vietnam Total Costs Opex USD 0 341 250 682 500 905 250 1 128 000 1 350 750 1 533 000 1 715 250 1 897 500 2 079 750 2 262 000 2 262 000 2 262 000 2 262 000 2 262 000 2 262 000 Planning (existing) --> 0% 50% 50% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Cost/unit n.unit Cost Planning (new) --> 0% 11% 11% 11% 11% 11% 9% 9% 9% 9% 9% 0% 0% 0% 0% 0% 2 400 000 5 500 kV substations retrofitting USD 0 6 000 000 6 000 000 0 0 0 0 0 0 0 0 0 0 0 0 0 900 000 13 220 kV substations retrofitting USD 0 5 850 000 5 850 000 0 0 0 0 0 0 0 0 0 0 0 0 0 CAPEX 2 400 000 45 500 kV new substations USD 0 11 880 000 11 880 000 11 880 000 11 880 000 11 880 000 9 720 000 9 720 000 9 720 000 9 720 000 9 720 000 0 0 0 0 0 900 000 105 220 kV new substations USD 0 10 395 000 10 395 000 10 395 000 10 395 000 10 395 000 8 505 000 8 505 000 8 505 000 8 505 000 8 505 000 0 0 0 0 0 Cost/year (absolute Cost/year (% at 100% of Capex) deployment) 1% 500 kV substations retrofitting USD 0 60 000 120 000 120 000 120 000 120 000 120 000 120 000 120 000 120 000 120 000 120 000 120 000 120 000 120 000 120 000 1% 220 kV substations retrofitting USD 0 58 500 117 000 117 000 117 000 117 000 117 000 117 000 117 000 117 000 117 000 117 000 117 000 117 000 117 000 117 000 OPEX 1% 500 kV new substations USD 0 118 800 237 600 356 400 475 200 594 000 691 200 788 400 885 600 982 800 1 080 000 1 080 000 1 080 000 1 080 000 1 080 000 1 080 000 1% 220 kV new substations USD 0 103 950 207 900 311 850 415 800 519 750 604 800 689 850 774 900 859 950 945 000 945 000 945 000 945 000 945 000 945 000 Hypothesis Number of SAS 50 Number of substations 164 180 197 213 230 246 260 273 287 300 314 314 314 314 314 314 until 2014: ENS cost ($/MWh) 3 000 Total existing Substations equipped with SAS 50 59 68 68 68 68 68 68 68 68 68 68 68 68 68 68 Avoided ENS per 100 New Substations equipped with SAS 0 17 33 50 66 83 96 110 123 137 150 150 150 150 150 150 SAS (MWh/year) Transmission system OPEX 19 200 000 Substations equipped with SAS after 2015 0 26 51 68 84 101 114 128 141 155 168 168 168 168 168 168 BENEFITS reduction ($/year) Installation pace for new substations 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 ENS reduction MWh 0 0 2 550 5 100 6 750 8 400 10 050 11 400 12 750 14 100 15 450 16 800 16 800 16 800 16 800 16 800 Improve system reliability through reduced frequency and duration USD 0 0 7 650 000 15 300 000 20 250 000 25 200 000 30 150 000 34 200 000 38 250 000 42 300 000 46 350 000 50 400 000 50 400 000 50 400 000 50 400 000 50 400 000 of system faults Direct Transmission OPEX reduction (automation and operational USD 0 0 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 19 200 000 efficiency)    Source: Authors CESI    COST‐BENEFIT ANALYSIS    B5013477   G.3  Wide Area Monitoring System (WAMS)  247.  Table  57  shows  that  the  major  costs  are  concentrated  in  the  first  few  years  because  of  the  huge  implementation  costs  for  the  existing  substations  in  the  network.  The  benefits  increase  over  the  same  period  because  of  the  cumulative  effects  of  old  and  new  installed  PMUs.  Maximum  annual  value  of  costs  is  TABLE 57: WAMS COSTS AND BENEFITS COMPARISON $436,560, which occurs in the second year of investment; while maximum yearly value of benefits is $5,068,651 occur in the last few years of the timeline.  Table 57: WAMS costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 22 951 362 EIRR 204% B/C ratio 17.82 % of events prevented to break-even ( considering 4.94% Transmission OPEX reduction benefit equal to zero ) unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 0 0 3 683 479 3 759 817 3 842 484 3 927 478 4 020 774 4 123 311 4 236 110 4 360 285 4 476 314 4 603 945 4 744 339 4 898 773 5 068 651 a. Direct Transmission OPEX reduction (automation USD 0 0 0 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 and operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 0 0 483 479 559 817 642 484 727 478 820 774 923 311 1 036 110 1 160 285 1 276 314 1 403 945 1 544 339 1 698 773 1 868 651 c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 frequency and duration of system faults e. Avoided CAPEX and Deferred Capacity USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Investments Total Costs USD 0 432 280 436 560 141 880 143 200 144 520 121 600 122 680 123 760 124 840 125 920 17 920 17 920 17 920 17 920 17 920 Total Costs Capex USD 0 428 000 428 000 132 000 132 000 132 000 108 000 108 000 108 000 108 000 108 000 0 0 0 0 0 Total Costs Opex USD 0 4 280 8 560 9 880 11 200 12 520 13 600 14 680 15 760 16 840 17 920 17 920 17 920 17 920 17 920 17 920 Planning (existing) --> 0% 50% 50% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Cost/unit n.unit Cost Planning (new) --> 0% 11% 11% 11% 11% 11% 9% 9% 9% 9% 9% 0% 0% 0% 0% 0% 8 000 74 PMU installation 500 and 220 kV existing substations USD 0 296 000 296 000 0 0 0 0 0 0 0 0 0 0 0 0 0 CAPEX 8 000 150 PMU installation 500 and 220 kV new substations USD 0 132 000 132 000 132 000 132 000 132 000 108 000 108 000 108 000 108 000 108 000 0 0 0 0 0 Cost/year (absolute at Cost/year (% 100% of Capex) deployment) 1% O&M PMU 500 and 220 kV existing substations USD 0 2 960 5 920 5 920 5 920 5 920 5 920 5 920 5 920 5 920 5 920 5 920 5 920 5 920 5 920 5 920 OPEX 1% O&M PMU 500 and 220 kV new substations USD 0 1 320 2 640 3 960 5 280 6 600 7 680 8 760 9 840 10 920 12 000 12 000 12 000 12 000 12 000 12 000 Faults events equivalent to a 10% brownout of 30 minutes per year Hypothesis Number of PMU until 4 Number of substations 164 180 197 213 230 246 260 273 287 300 314 314 314 314 314 314 2014: % of events 20% Old Substation equipped with PMUs after 2015 0 37 74 74 74 74 74 74 74 74 74 74 74 74 74 74 prevented Transmission system OPEX 3 200 000 New Substation equipped with PMUs 0 17 33 50 66 83 96 110 123 137 150 150 150 150 150 150 reduction BENEFITS ($/year) Substation equipped with PMUs 0 54 107 124 140 157 170 184 197 211 224 224 224 224 224 224 installation pace of new substations 0% 11% 11% 11% 11% 11% 9% 9% 9% 9% 9% 0% 0% 0% 0% 0% Interrupion cost USD 3 135 375 3 448 913 3 793 804 4 173 184 4 590 503 5 049 553 5 554 508 6 109 959 6 720 955 7 393 050 8 132 355 8 945 591 9 840 150 10 824 165 11 906 581 13 097 239 ENS MWh 1 125 1 238 1 361 1 497 1 647 1 812 1 993 2 192 2 412 2 653 2 918 3 210 3 531 3 884 4 272 4 699 Reduction of Energy Not Served USD 0 0 0 483 479 559 817 642 484 727 478 820 774 923 311 1 036 110 1 160 285 1 276 314 1 403 945 1 544 339 1 698 773 1 868 651 Direct Transmission OPEX reduction (automation and USD 0 0 0 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 operational efficiency)     Source: Authors Volume 2: Cost-Benefit Analysis 187 The picture can't be display ed.     188   G.4 Lightning Location System (LLS) CESI   COST‐BENEFIT  ANALYSIS     B5013477 Table 58 shows that the costs occur only in the first few years because of the installation of the LLS smart grid application (that is in addition to network expansion).   The benefits increase over the time because of the cumulative effect on an increasingly extended power system. Maximum yearly value of costs is $1,090,000, Lightning G.4 which  Location occurs in  System the second  (LLS)  while maximum yearly value of benefits of $2,284,862 occurs in the last year of the timeline. year of investment, 248.  Table  58  shows  that  the  costs  occur  only  in  the  first  few  years  because  of  the  installation  of  the  LLS  smart  grid  application  (that  is  in  addition  to  network  expansion). The benefits increase over the time because of the cumulative effect on an increasingly extended power system. Maximum yearly value of costs  TABLE 58: LIGHTNING LOCATION SYSTEM COSTS AND BENEFITS COMPARISON is $1,090,000, which occurs in the second year of investment, while maximum yearly value of benefits of $2,284,862 occurs in the last year of the timeline.  Table 58: Lightning Location System costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 11 035 144 EIRR 164% B/C ratio 6.89 % of events prevented to break-even ( considering 21.3% Transmission OPEX reduction benefit equal to zero ) unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 0 1 789 690 1 808 659 1 829 525 1 852 478 1 877 725 1 905 498 1 936 048 1 969 653 2 006 618 2 047 280 2 092 007 2 141 208 2 195 329 2 254 862 a. Direct Transmission OPEX reduction (automation USD 0 0 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 and operational efficiency) USD 0 0 189 690 208 659 229 525 252 478 277 725 305 498 336 048 369 653 406 618 447 280 492 007 541 208 595 329 654 862 Smart Grid to Enhance Power Transmission in Vietnam b. Reduction of Energy Not Served (ENS) c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 frequency and duration of system faults e. Avoided CAPEX and Deferred Capacity USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Investments Total Costs USD 0 671 000 1 090 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 Total Costs Capex USD 0 640 000 1 028 000 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Costs Opex USD 0 31 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 62 000 Cost/unit n.unit Cost Planning (new) --> 0% 50% 50% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 54 000 20 Lightning detectors USD 0 540 000 540 000 0 0 0 0 0 0 0 0 0 0 0 0 0 10 000 20 Civil works USD 0 100 000 100 000 0 0 0 0 0 0 0 0 0 0 0 0 0 Telecommunication between detectors and control center, 30 000 1 CAPEX USD 0 0 30 000 0 0 0 0 0 0 0 0 0 0 0 0 0 data collection and management (ADSL, Routers, DB's) 172 000 1 Lightning Location Central Analyzer software USD 0 0 172 000 0 0 0 0 0 0 0 0 0 0 0 0 0 186 000 1 Archiving and handling of Lightning data software USD 0 0 186 000 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost/year Cost/year (absolute at (% 100% of deployment) Capex) 10 000 Site rental USD 0 5 000 10 000 10 000 10 000 10 000 10 000 10 000 10 000 10 000 10 000 10 000 10 000 10 000 10 000 10 000 4 000 Electricity supply USD 0 2 000 4 000 4 000 4 000 4 000 4 000 4 000 4 000 4 000 4 000 4 000 4 000 4 000 4 000 4 000 OPEX 24 000 Data analysis USD 0 12 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 Hardware and software operation and maintenance USD 0 12 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 24 000 Faults events equivalent to a 2% brownout of 30 minutes per year Hypothesis % of events 25% Interrupion cost USD 627 075 689 783 758 761 834 637 918 101 1 009 911 1 110 902 1 221 992 1 344 191 1 478 610 1 626 471 1 789 118 1 968 030 2 164 833 2 381 316 2 619 448 prevented Transmission system OPEX reduction 1 600 000 ENS MWh 225 248 272 299 329 362 399 438 482 531 584 642 706 777 854 940 BENEFITS ($/year) Reduction of Energy Not Served USD 0 0 189 690 208 659 229 525 252 478 277 725 305 498 336 048 369 653 406 618 447 280 492 007 541 208 595 329 654 862 Direct Transmission OPEX reduction (automation and USD 0 0 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 operational efficiency)   Source: Authors The picture can't be display ed.     G.5 Static Var Compensator (SVC) CESI    Table COST59‐BENEFIT shows  that the costs ANALYSIS   are present only in the first few years of the installation of the SVC smart grid application. The benefits increase over the   because B5013477 time   because of the cumulative effect on an increasingly extended power system. Maximum yearly value of costs is $7 ,968,000, which occurs in the second year of investment, G.5  Static while  Var maximum Compensator value of yearly (SVC)   benefits of $6,474,410 occur in the last year of the timeline. 249.  Table 59 shows that the costs are present only in the first few years because of the installation of the SVC smart grid application. The benefits increase over  the  time  because  of  the  cumulative  effect  on  an  increasingly  extended  power  system.  Maximum  yearly  value  of  costs  is  $7,968,000,  which  occurs  in  the  TABLE second year of 59: SVC  COSTS  investment, AND BENEFITS  while  maximum yearly value of benefits of $6,474,410 occur in the last year of the timeline.  COMPARISON   Table 59: SVC costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 5 265 412 EIRR 14.21% B/C ratio 1.21 % of events prevented to break-even ( considering 60.3% Transmission OPEX reduction benefit equal to zero ) unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 1 015 557 2 074 225 3 182 472 4 347 626 4 462 388 4 588 627 4 727 490 4 880 239 5 048 263 5 233 089 5 436 398 5 660 037 5 906 041 6 176 645 6 474 310 a. Direct Transmission OPEX reduction (automation USD 0 800 000 1 600 000 2 400 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 and operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 215 557 474 225 782 472 1 147 626 1 262 388 1 388 627 1 527 490 1 680 239 1 848 263 2 033 089 2 236 398 2 460 037 2 706 041 2 976 645 3 274 310 c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 frequency and duration of system faults e. Avoided CAPEX and Deferred Capacity USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Investments Total Costs USD 0 7 898 250 7 921 500 7 944 750 7 968 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 Total Costs Capex USD 0 7 875 000 7 875 000 7 875 000 7 875 000 0 0 0 0 0 0 0 0 0 0 0 Total Costs Opex USD 0 23 250 46 500 69 750 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 93 000 Cost/Mvar Mvar Cost Planning (new) --> 0% 25% 25% 25% 25% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 30 000 900 Static Var Compensator (relocatable) USD 0 6 750 000 6 750 000 6 750 000 6 750 000 0 0 0 0 0 0 0 0 0 0 0 CAPEX 5 000 900 Civil works USD 0 1 125 000 1 125 000 1 125 000 1 125 000 0 0 0 0 0 0 0 0 0 0 0 Cost/year (absolute at Cost/year (% 100% of Capex) deployment) 60 000 Preventive maintenance (3 days/year) + On-line support USD 0 15 000 30 000 45 000 60 000 60 000 60 000 60 000 60 000 60 000 60 000 60 000 60 000 60 000 60 000 60 000 30 000 OPEX Corrective maintenance USD 0 7 500 15 000 22 500 30 000 30 000 30 000 30 000 30 000 30 000 30 000 30 000 30 000 30 000 30 000 30 000 3 000 Spares e consumables USD 0 750 1 500 2 250 3 000 3 000 3 000 3 000 3 000 3 000 3 000 3 000 3 000 3 000 3 000 3 000 Faults events equivalent to a 10% brownout of 30 minutes per year Hypothesis % of events prevented 25% Interrupion cost USD 3 135 375 3 448 913 3 793 804 4 173 184 4 590 503 5 049 553 5 554 508 6 109 959 6 720 955 7 393 050 8 132 355 8 945 591 9 840 150 10 824 165 11 906 581 13 097 239 (100% of deployment) Transmission system OPEX 3 200 000 BENEFITS ENS MWh 1 125 1 238 1 361 1 497 1 647 1 812 1 993 2 192 2 412 2 653 2 918 3 210 3 531 3 884 4 272 4 699 reduction ($/year) Reduction of Energy Not Served USD 0 215 557 474 225 782 472 1 147 626 1 262 388 1 388 627 1 527 490 1 680 239 1 848 263 2 033 089 2 236 398 2 460 037 2 706 041 2 976 645 3 274 310 Direct Transmission OPEX reduction (automation and USD 0 800 000 1 600 000 2 400 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 3 200 000 operational efficiency)       Source: Authors Volume 2: Cost-Benefit Analysis 189 The picture can't be display ed.     190 G.6 High Voltage Direct Current (HVDC) technology CESI    COST Table ‐BENEFIT 60  ANALYSIS shows that the costs are     only in the first few years owing to the construction B5013477 phase of the HVDC system. The benefits do not change over the time because   the assumption of power losses cost is the same over the period. Maximum yearly value of incremental costs is $8,748,000 in the last part of the timeline due to of G.6 the   High high  Voltage incremental  Direct OPEX,  Current while the yearly (HVDC) technology value of  benefits   is $12,800,000. 250.  Table 60 shows that the costs are only in the first few years owing to the construction phase of the HVDC system. The benefits do not change over the time  because of the assumption of power losses cost is the same over the period. Maximum yearly value of incremental costs is $8,748,000 in the last part of the  TABLE 60: HVDC COSTS AND BENEFITS COMPARISON timeline due to the high incremental OPEX, while the yearly value of benefits is $12,800,000.  Table 60: HVDC costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 23 524 111 EIRR ALL POSITIVE CASH FLOWS B/C ratio 1.56 Line length [km] to break-even ( considering 773 Transmission OPEX reduction benefit equal to zero ) unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 0 0 0 12 800 000 12 800 000 12 800 000 12 800 000 12 800 000 12 800 000 12 800 000 12 800 000 12 800 000 12 800 000 12 800 000 12 800 000 a. Direct Transmission OPEX reduction (automation USD 0 0 0 0 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 and operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Smart Grid to Enhance Power Transmission in Vietnam c. Reduction of power losses USD 0 0 0 0 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 d. Improve system reliability through reduced USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 frequency and duration of system faults e. Avoided CAPEX and Deferred Capacity Investments USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Costs USD 0 -2 013 000 174 000 2 361 000 4 548 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 Total Costs Capex USD 0 -4 200 000 -4 200 000 -4 200 000 -4 200 000 0 0 0 0 0 0 0 0 0 0 0 Total Costs Opex USD 0 2 187 000 4 374 000 6 561 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 8 748 000 Cost/unit unit Cost Planning (new) --> 0% 25% 25% 25% 25% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% HVDC Overhead lines engineering, procurement and 345 000 800 USD 0 69 000 000 69 000 000 69 000 000 69 000 000 0 0 0 0 0 0 0 0 0 0 0 construction 200 000 000 2 HVDC Converter stations USD 0 100 000 000 100 000 000 100 000 000 100 000 000 0 0 0 0 0 0 0 0 0 0 0 HVAC Overhead lines engineering, procurement and 560 000 800 USD 0 -112 000 000 -112 000 000 -112 000 000 -112 000 000 0 0 0 0 0 0 0 0 0 0 0 construction (Avoided Capex) CAPEX HVAC Cost of additional equipment (Substations, feeders, 44 800 000 1 USD 0 -11 200 000 -11 200 000 -11 200 000 -11 200 000 0 0 0 0 0 0 0 0 0 0 0 Facts, ...) (Avoided Capex) Righ-of-Way width 25 HVAC additional right of way cost (Avoided Capex) USD 0 -50 000 000 -50 000 000 -50 000 000 -50 000 000 0 0 0 0 0 0 0 0 0 0 0 reduction [m] Right-of-Way average 10 2 cost [$/m ] Cost/year (absolute at Cost/year 100% of deployment) (% Capex) 1.5% HVDC OHL O&M USD 0 1 035 000 2 070 000 3 105 000 4 140 000 4 140 000 4 140 000 4 140 000 4 140 000 4 140 000 4 140 000 4 140 000 4 140 000 4 140 000 4 140 000 4 140 000 3% HVDC O&M Converter stations USD 0 3 000 000 6 000 000 9 000 000 12 000 000 12 000 000 12 000 000 12 000 000 12 000 000 12 000 000 12 000 000 12 000 000 12 000 000 12 000 000 12 000 000 12 000 000 1.5% OPEX HVAC OHL O&M (Avoided Opex) USD 0 -1 848 000 -3 696 000 -5 544 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 -7 392 000 USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Hypothesis Cost of losses HVDC Direct Transmission OPEX reduction (automation and 40 000 USD 0 0 0 0 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 lines [$/km/year] operational efficiency) Cost of losses HVDC 8 800 000 Reduction of power losses USD 0 0 0 0 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 11 200 000 converters [$/year] Cost of losses AC BENEFITS 65 000 lines [$/km/year] Transmission system OPEX reduction 1 600 000 ($/year)   Source: Authors The picture can't be display ed.     G.7 Fault Locator System (FLS) Table 61 reports that the major costs are only in the first few years because of the installation of the FLS smart grid application. The benefits increase over the time CESI    because of the cumulative effect on an increasingly extended power system. Maximum yearly value of costs is $4,200,000 in the first year of investment, while COST‐BENEFIT ANALYSIS    B5013477 maximum yearly value of benefits of $2,455,732 occurs in the last year of the timeline.   G.7  Fault Locator System (FLS)  251.  Table 61 reports that the major costs are only in the first few years because of the installation of the FLS smart grid application. The benefits increase over  the  time  because  of  the  cumulative  effect  on  an  increasingly  extended  power  system.  Maximum  yearly  value  of  costs  is  $4,200,000  in  the  first  year  of  investment, while maximum yearly value of benefits of $2,455,732 occurs in the last year of the timeline.    TABLE 61: FLS COSTS AND BENEFITS COMPARISON Table 61: FLS costs and benefits comparison (Source: Authors)    DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 1 235 045 EIRR 13% B/C ratio 1.17 % monitored lines with faults to break-even 64.1% unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 323 336 711 338 782 472 860 719 946 791 1 041 470 1 145 617 1 260 179 1 386 197 1 524 817 1 677 298 1 845 028 2 029 531 2 232 484 2 455 732 a. Direct Transmission OPEX reduction USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 (automation and operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 323 336 711 338 782 472 860 719 946 791 1 041 470 1 145 617 1 260 179 1 386 197 1 524 817 1 677 298 1 845 028 2 029 531 2 232 484 2 455 732 c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced frequency and duration of system USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 faults e. Avoided CAPEX and Deferred Capacity USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Investments Total Costs USD 0 4 200 000 4 200 000 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Costs Capex USD 0 4 200 000 4 200 000 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Costs Opex USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost/unit unit Cost Planning (new) --> 0% 50% 50% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 60 000 140 CAPEX Equipment USD 0 4 200 000 4 200 000 0 0 0 0 0 0 0 0 0 0 0 0 0 Faults events equivalent to a 10 % brownout of 30 Hypothesis minutes per year % of outage time 25% Interrupion cost USD 3 135 375 3 448 913 3 793 804 4 173 184 4 590 503 5 049 553 5 554 508 6 109 959 6 720 955 7 393 050 8 132 355 8 945 591 9 840 150 10 824 165 11 906 581 13 097 239 duration % monitored lines with BENEFITS faults at 100% of 75% ENS MWh 1 125 1 238 1 361 1 497 1 647 1 812 1 993 2 192 2 412 2 653 2 918 3 210 3 531 3 884 4 272 4 699 deployment) Reduction of Energy Not Served USD 0 323 336 711 338 782 472 860 719 946 791 1 041 470 1 145 617 1 260 179 1 386 197 1 524 817 1 677 298 1 845 028 2 029 531 2 232 484 2 455 732     Source: Authors     Volume 2: Cost-Benefit Analysis 191 The picture can't be display ed. 192     G.8 On-line Dissolved Gas-in-oil Analysis (DGA) CESI    Table 62 shows that the costs are spread over the years and the benefits increase because of the cumulative effects of old and new installed sensors. Maximum BENEFIT  ANALYSIS     B5013477 COST‐value yearly of costs is $7,300,785, which occurs in the second year of investment, while maximum yearly value of benefits of $12,425,508 occurs in the last year   of the timeline. G.8  On‐line Dissolved Gas‐in‐oil Analysis (DGA)  252.  Table  62  shows  that  the  costs  are  spread  over  the  years  and  the  benefits  increase  because  of  the  cumulative  effects  of  old  and  new  installed  sensors.  Maximum yearly value of costs is $7,300,785, which occurs in the second year of investment, while maximum yearly value of benefits of $12,425,508 occurs  TABLE 62: DGA COSTS AND BENEFITS COMPARISON in the last year of the timeline.  Table 62: DGA costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 5 532 566 EIRR 12% B/C ratio 1.13 Average cost of a transformer fault [$] to break-even 7907 unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 1 363 768 2 727 537 3 495 955 4 264 374 5 032 792 5 859 505 6 686 217 7 512 929 8 339 642 9 166 354 9 818 185 10 470 015 11 121 846 11 773 677 12 425 508 a. Direct Transmission OPEX reduction (automation USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Smart Grid to Enhance Power Transmission in Vietnam and operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 frequency and duration of system faults e. Avoided CAPEX and Deferred Capacity USD 0 1 363 768 2 727 537 3 495 955 4 264 374 5 032 792 5 859 505 6 686 217 7 512 929 8 339 642 9 166 354 9 818 185 10 470 015 11 121 846 11 773 677 12 425 508 Investments Total Costs USD 0 7 264 643 7 300 785 5 099 798 5 124 810 5 149 823 5 556 233 5 583 143 5 610 053 5 636 963 5 663 873 4 546 590 4 567 808 4 589 025 4 610 243 4 631 460 Total Costs Capex USD 0 7 228 500 7 228 500 5 002 500 5 002 500 5 002 500 5 382 000 5 382 000 5 382 000 5 382 000 5 382 000 4 243 500 4 243 500 4 243 500 4 243 500 4 243 500 Total Costs Opex USD 0 36 143 72 285 97 298 122 310 147 323 174 233 201 143 228 053 254 963 281 873 303 090 324 308 345 525 366 743 387 960 Planning (existing) --> 0% 50% 50% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Cost/unit unit Cost Planning (new) --> 0% 7% 7% 7% 7% 7% 7% 7% 7% 7% 7% 6% 6% 6% 6% 6% 106 000 42 Sensors on existing transformers USD 0 2 226 000 2 226 000 0 0 0 0 0 0 0 0 0 0 0 0 0 CAPEX 106 000 690 Sensors on new transformers USD 0 5 002 500 5 002 500 5 002 500 5 002 500 5 002 500 5 382 000 5 382 000 5 382 000 5 382 000 5 382 000 4 243 500 4 243 500 4 243 500 4 243 500 4 243 500 Cost/year (absolute at Cost/ye ar (% 100% of deployment) Capex) 0.5% O&M DGA existing transformers USD 0 11 130 22 260 22 260 22 260 22 260 22 260 22 260 22 260 22 260 22 260 22 260 22 260 22 260 22 260 22 260 OPEX 0.5% O&M DGA new transformers USD 0 25 013 50 025 75 038 100 050 125 063 151 973 178 883 205 793 232 703 259 613 280 830 302 048 323 265 344 483 365 700 Hypothesis Fault 0.60% probability Average cost of a 9 000 transformer fault [$/MVA] BENEFITS Avoided CAPEX USD 0 1 363 768 2 727 537 3 495 955 4 264 374 5 032 792 5 859 505 6 686 217 7 512 929 8 339 642 9 166 354 9 818 185 10 470 015 11 121 846 11 773 677 12 425 508 New capacity to be 208 052 installed [MVA]       Source: Authors The picture can't be display ed.     CESI    G.9 COST Dynamic ‐BENEFIT Thermal  ANALYSIS  Circuit Rating (DTCR)   B5013477   63 shows Dynamic G.9  Table  Thermal costs are that the Circuit only in the  Rating first few  (DTCR)   years owing to the installation phase on the monitored lines. The benefits are also mainly in the first part of the timeline because of the immediately avoided CAPEX achieved with the technology. Maximum yearly value of incremental costs is $665,600 occurring in the second year of investment, while maximum yearly value of benefits is $21,600,000. 253.  Table 63 shows that the costs are only in the first few years owing to the installation phase on the monitored lines. The benefits are also mainly in the first  part  of  the  timeline  because  of  the  immediately  avoided  CAPEX  achieved  with  the  technology.  Maximum  yearly  value  of  incremental  costs  is  $665,600  occurring in the second year of investment, while maximum yearly value of benefits is $21,600,000.  TABLE 63: DTCR COSTS AND BENEFITS COMPARISON   Table 63: DTCR costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 44 132 102 EIRR ALL POSITIVE CASH FLOWS B/C ratio 35.11 Number of year deferred to break-even ( considering 0.18 Transmission OPEX reduction benefit equal to zero ) unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 20 000 000 21 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 a. Direct Transmission OPEX reduction (automation USD 0 0 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 and operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 frequency and duration of system faults e. Avoided CAPEX and Deferred Capacity Investments USD 0 20 000 000 20 000 000 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Costs USD 0 652 800 665 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 Total Costs Capex USD 0 640 000 640 000 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Costs Opex USD 0 12 800 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 Cost/unit unit Cost Planning (new) --> 0% 50% 50% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 32 000 40 Line lenght: 100 Number of lines 4 Sensors USD 0 640 000 640 000 0 0 0 0 0 0 0 0 0 0 Number of sensors per 100 10 km Cost/year (absolute at Cost/year 100% of (% Capex) deployment) 2.0% O&M DTCR USD 0 12 800 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 25 600 Cost of line reconductoring 200 000 [$/km] Number of years 5 deferred Number of Direct Transmission OPEX reduction (automation and avoided line 4 USD 0 0 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 operational efficiency) reconductoring Transmission system OPEX 1 600 000 reduction ($/year)       Source: Authors Volume 2: Cost-Benefit Analysis 193 The picture can't be display ed.     194   G.10 Geographic CESI Information Systems (GIS)   Table 64 COST shows  that ‐BENEFIT the major ANALYSIS     costs are only in the first few years because of the installation of this new smart grid application. The benefits increase over the time B5013477  because of the cumulative effect on an increasingly extended power system. Maximum yearly value of costs is $192,500 in the first year of investment, while maxi- G.10 mum yearly Geographic benefits of $226,200 value of Information occurs  Systems in the  (GIS)   last years of the timeline. 254.  Table 64 shows that the major costs are only in the first few years because of the installation of this new smart grid application. The benefits increase over  the  time  because  of  the  cumulative  effect  on  an  increasingly  extended  power  system.  Maximum  yearly  value  of  costs  is  $192,500  in  the  first  year  of  investment, while maximum yearly value of benefits of $226,200 occurs in the last years of the timeline.   TABLE 64: GIS COSTS AND BENEFITS COMPARISON Table 64: GIS costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 762 214 EIRR 48% B/C ratio 3.61 % reduction of SAS O&M to break-even 2.70% unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 0 68 250 90 525 112 800 135 075 153 300 171 525 189 750 207 975 226 200 226 200 226 200 226 200 226 200 226 200 Smart Grid to Enhance Power Transmission in Vietnam a. Direct Transmission OPEX reduction USD 0 0 68 250 90 525 112 800 135 075 153 300 171 525 189 750 207 975 226 200 226 200 226 200 226 200 226 200 226 200 (automation and operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced frequency and duration of USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 system faults e. Avoided CAPEX and Deferred USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Capacity Investments Total Costs USD 0 192 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 Total Costs Capex USD 0 175 000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Total Costs Opex USD 0 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 Cost/unit unit Cost Planning (new) --> 0% 100% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 150 000 1 Software applications USD 0 150 000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 25 000 1 CAPEX Hardware equipments USD 0 25 000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost/year (absolute at Cost/year (% 100% of Capex) deployment) 10.0% OPEX Hardware and software maintenance USD 0 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 17 500 Hypothesis % O&M of Direct Transmission OPEX reduction 10.0% BENEFITS USD 0 0 68 250 90 525 112 800 135 075 153 300 171 525 189 750 207 975 226 200 226 200 226 200 226 200 226 200 226 200 SAS (automation and operational efficiency)       Source: Authors The picture can't be display ed.     G.11 Power quality monitoring and Metering Data Acquisition Systems CESI     Table 65 reports that the major costs are present mainly in the first few years because of the implementation this technology in the power system. The benefits increase COST over the ‐BENEFIT time because  ANALYSIS   of the cumulative effects of old and  new installed analyzers in the expanding network. Maximum yearly value of costs is $203,051 B5013477   in the first year of investment, while maximum yearly value of benefits of $1,794,110 occurs in the last years of the timeline. G.11  Power quality monitoring and Metering Data Acquisition Systems  255.  Table  65  reports  that  the  major  costs  are  present  mainly  in  the  first  few  years  because  of  the  implementation  this  technology  in  the  power  system.  The  benefits  increase  over  the  time  because  of  the  cumulative  effects  of  old  and  new  installed  analyzers  in  the  expanding  network.  Maximum  yearly  value  of  TABLE 65: POWER costs QUALITY  is $203,051 MONITORING  in the AND  first year of METERING  investment,  while DATA ACQUISITION maximum yearly SYSTEMS  value COSTS AND BENEFITS  of benefits COMPARISON  of $1,794,110  occurs in the last years of the timeline.  Table 65: Power quality monitoring and Metering Data Acquisition Systems costs and benefits comparison (Source: Authors)  DISCOUNT RATE 10.0% INVESTMENT DURATION (YEARS) 15 Total NPV 2030 [$] 11 003 193 EIRR 797% B/C ratio 39.26 % of events prevented to break-even ( considering 10.0% Transmission OPEX reduction benefit equal to zero ) unit 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Total Benefits USD 0 0 1 635 243 1 641 996 1 649 747 1 658 628 1 668 064 1 678 791 1 690 983 1 704 826 1 720 527 1 732 580 1 745 838 1 760 422 1 776 464 1 794 110 a. Direct Transmission OPEX reduction (automation USD 0 0 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 and operational efficiency) b. Reduction of Energy Not Served (ENS) USD 0 0 35 243 41 996 49 747 58 628 68 064 78 791 90 983 104 826 120 527 132 580 145 838 160 422 176 464 194 110 c. Reduction of power losses USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 d. Improve system reliability through reduced USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 frequency and duration of system faults e. Avoided CAPEX and Deferred Capacity USD 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Investments Total Costs USD 0 203 051 17 331 17 699 18 090 18 482 16 682 16 983 17 307 17 632 17 957 7 500 7 500 7 500 7 500 7 500 Total Costs Capex USD 0 198 742 12 630 12 606 12 606 12 606 10 481 10 457 10 457 10 457 10 457 0 0 0 0 0 Total Costs Opex USD 0 4 309 4 701 5 093 5 484 5 876 6 201 6 526 6 851 7 175 7 500 7 500 7 500 7 500 7 500 7 500 Planning (software) --> 0% 100% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Cost/unit unit Cost Planning (new) --> 0% 57% 5% 5% 5% 5% 4% 4% 4% 4% 4% 0% 0% 0% 0% 0% 2 300 105 Equipment USD 0 138 742 12 630 12 606 12 606 12 606 10 481 10 457 10 457 10 457 10 457 0 0 0 0 0 CAPEX 60 000 1 Software licence and hardware in the control center USD 0 60 000 0 0 0 0 0 0 0 0 0 0 0 0 0 0 Cost/year (absolute at Cost/year (% Capex) 100% of deployment) 6 000 O&M control center + software updates USD 0 3 447 3 761 4 074 4 387 4 700 4 961 5 221 5 480 5 740 6 000 6 000 6 000 6 000 6 000 6 000 OPEX 1 500 Data analysis USD 0 862 940 1 019 1 097 1 175 1 240 1 305 1 370 1 435 1 500 1 500 1 500 1 500 1 500 1 500 Faults events equivalent to a 1% brownout of 15 minutes per Hypothesis year % of events prevented 20% Interrupion cost USD 232 342 255 576 281 134 309 247 340 172 374 189 411 608 452 769 498 046 547 851 602 636 662 899 729 189 802 108 882 319 970 551 (100% of deployment) Transmission system OPEX BENEFITS 1 600 000 ENS MWh 56 62 68 75 82 91 100 110 121 133 146 160 177 194 214 235 reduction ($/year) Reduction of Energy Not Served USD 0 0 35 243 41 996 49 747 58 628 68 064 78 791 90 983 104 826 120 527 132 580 145 838 160 422 176 464 194 110 Direct Transmission OPEX reduction (automation and USD 0 0 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 1 600 000 operational efficiency)   Source: Authors Volume 2: Cost-Benefit Analysis 195 H. Sensitivity Analysis H.1 Key Points Summary H.2 Energy Not Served value sensitivity analysis The Sensitivity Analysis is an approach used for investi- gating the impact of changes in the variables of projects Table 66 shows that many Smart Grid applications are relative to the baseline scenario as described in the previ- heavily dependent on the financial value assumed for ous chapters. energy not served (or Value of Loss Load). The variables assumed for the assessment vary depend- The economic results are derived by conducting the sen- ing on the project under investigation. For this reason sitivity analysis on the ENS value for all the initiatives each Smart Grid initiative has been analyzed in order to affected by this parameter and are shown below in Table identify those variables that are characterized by a high 67 (NPV), Table 68 (EIRR) and Table 69 (B/C ratio). The uncertainty and at the same time have a great impact on results of the baseline scenario are listed in bold. the economic evaluation. Table 66 summarizes the sensitivity analysis parameters of each Smart Grid initiative. TABLE 66: SUMMARY OF THE SENSITIVITY ANALYSIS PARAMETERS OF SMART GRID INITIATIVES Initiative Sensitivity analysis parameters Energy Not Served value SAS Average value of annually ENS reduction per substation equipped with SAS Energy Not Served value WAMS Percentage of fault events prevented Energy Not Served value Lightning Location System Percentage of fault events prevented Energy Not Served value SVC Percentage of fault events prevented Power losses cost HVDC Line length Energy Not Served value FLS Reduction of outage time duration Percentage of lines with faults monitored by FLS DGA Average cost of a transformer fault Number of lines with deferred reconductoring Dynamic Thermal Circuit Rating Number of years of deferred investment GIS Operation and maintenance cost savings for SAS application Power quality monitoring and Energy Not Served value Metering Data Acquisition Systems Percentage of fault events prevented Source: Authors 196 Volume 2: Cost-Benefit Analysis 197 TABLE 67: NPV FOR DIFFERENT ENS VALUE ASSUMPTION Total NPV [$] ENS VALUE $/MWh --> 2,000 $/MWh 2,500 $/MWh 3,000 $/MWh 3,500 $/MWh SAS 109,276,276 144,139,269 179,002,262 213,865,256 WAMS 21,107,844 22,031,389 22,951,362 23,874,906 LLS 10,303,557 10,670,059 11,035,144 11,401,647 SVC 1,738,115 3,505,181 5,265,412 7,032,478 FLS (1,606,389) (182,919) 1,235,045 2,658,514 PQ + Metering 10,811,319 10,907,461 11,003,193 11,099,336 Source: Authors TABLE 68: ECONOMIC INTERNAL RATE OF RETURN FOR DIFFERENT ENS VALUE ASSUMPTION EIRR ENS VALUE $/MWh --> 2,000 $/MWh 2,500 $/MWh 3,000 $/MWh 3,500 $/MWh SAS 31% 36% 41% 46% WAMS 198% 201% 204% 208% LLS 156% 160% 164% 168% SVC 11% 13% 14% 16% FLS 6% 10% 13% 16% PQ + Metering 791% 794% 797% 800% Source: Authors TABLE 69: B/C RATIO FOR DIFFERENT ENS VALUE ASSUMPTION B/C ratio ENS VALUE $/MWh --> 2,000 $/MWh 2,500 $/MWh 3,000 $/MWh 3,500 $/MWh SAS 1.69 1.91 2.13 2.35 WAMS 16.46 17.14 17.82 18.49 LLS 6.50 6.69 6.89 7.08 SVC 1.07 1.14 1.21 1.28 FLS 0.78 0.97 1.17 1.36 PQ + Metering 38.59 38.92 39.26 39.59 Source: Authors 198 Smart Grid to Enhance Power Transmission in Vietnam H.3 Substation Automation System (SAS) Due to the high value of the EIRR in the baseline sce- nario no sensitivity has been performed on the dis- The variable that has the greatest potential for affecting count rate. the final net benefit considerably is the average value of annual ENS reduction per substation equipped with SAS (100 MWh in the baseline scenario). H.5 Lightning Location System (LLS) Figure 91 shows the change of the economic indicators The variable that has the potential for affecting the final for ENS reduction (B/C ratio and Total NPV) varying from net benefit considerably is the percentage of fault events 50 MWh/year to 125 MWh/year for every substation prevented (25% in the baseline scenario). equipped with SAS. Figure 93 shows the effect on the economic indicators Owing to the high value of the EIRR in the baseline sce- (B/C ratio and Total NPV) caused by varying the percent- nario no sensitivity analysis has been performed on the age of fault events prevented from 10% to 30%. discount rate. Due to the high value of the EIRR in the baseline sce- nario no sensitivity has been performed on the dis- H.4 Wide Area Monitoring System count rate. (WAMS) The variable that has the potential for affecting the final H.6 Static Var Compensator (SVC) net benefit considerably is the percentage of fault events prevented (20% in the baseline scenario). The variable that has the potential for affecting alter the final net benefit considerably is the percentage of fault Figure 92 shows the effect on the economic indicators events prevented (25% in the baseline scenario). (B/C ratio and Total NPV) caused by varying the percent- age of fault events prevented from 10% to 25%. FIGURE 91: SAS SENSITIVITY ANALYSIS Source: Authors Volume 2: Cost-Benefit Analysis 199 FIGURE 92: WAMS SENSITIVITY ANALYSIS Source: Authors FIGURE 93: LIGHTNING LOCATION SYSTEM SENSITIVITY ANALYSIS Source: Authors 200 Smart Grid to Enhance Power Transmission in Vietnam Figure 94 shows the effect on the economic indicators H.8 Fault Locator System (FLS) (B/C ratio and Total NPV) caused by varying the percent- age of fault events prevented from 10% to 30%. The variables that have the potential for affecting the final net benefit considerably are: H.7 High Voltage Direct Current a. Reduction of outage duration (25%in the Base- (HVDC) technology line scenario); b. Percentage of lines with faults monitored with The variables that have the potential for affecting the final the FLS (10%in the baseline scenario). net benefit considerably are: As shown in Figure 97 , the “Reduction of energy not a. Power losses cost (60 $/MWh in the baseline served” benefit of FLS is proportional to the product of the scenario); two variables, for this reason a single sensitivity analysis can b. Line length (800 km in the baseline scenario). be performed by changing the values from the minimum to their maximum at the same time for both variables. Figure 95 shows the effect on the economic indicators (B/C ratio and Total NPV) caused by varying the power losses cost from 40 $/MWh to 80 $/MWh. H.9 On-line Dissolved Gas-in-oil Analysis (DGA) Figure 96 shows the effect on the economic indicators (B/C ratio and Total NPV) caused by varying a power line The variable that has the potential for affecting the final length from 700 km to 950 km. As can be seen, when net benefit considerably is the average cost of a trans- the line length is greater than 850 km the cost of a new former fault ($9,000 in the baseline scenario). HVAC link is greater than for a HVDC line which is indi- cated as a negative incremental cost. FIGURE 94: SVC SENSITIVITY ANALYSIS Source: Authors Volume 2: Cost-Benefit Analysis 201 FIGURE 95: HVDC SENSITIVITY ANALYSIS ON POWER LOSSES COST Source: Authors FIGURE 96: HVDC SENSITIVITY ANALYSIS ON LINE LENGTH Source: Authors 202 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 97: FLS SENSITIVITY ANALYSIS Source: Authors Figure 98 shows the effect on the economic indicators H.11 Geographic Information Systems (B/C ratio and Total NPV) caused by varying the average (GIS) cost of a transformer fault value from $6,750 to $11,250. The variable that has the potential for affecting the final net benefit considerably is the operation and mainte- H.10 Dynamic Thermal Circuit Rating nance cost savings generated by the SAS application (DTCR) (10% the baseline scenario). The variables that have the potential for affecting alter the Figure 100 shows the effect on the economic indicators final net benefit considerably are: (B/C ratio and Total NPV) caused by varying the average cost of a transformer fault value from 5% to 12.5%. a. Number of lines with deferred reconductoring (4 in the baseline scenario); b. Number of years of deferred investment (5 in the H.12 Power quality monitoring and baseline scenario). Metering Data Acquisition Systems As shown in Figure 99 the “Avoided CAPEX and Deferred Capacity Investments” , which is a benefit of DTCR is pro- The variable that has the potential for affecting the final portional to the product of the two variables thus allow- net benefit considerably is the percentage of faults ing a single sensitivity analysis to be performed for both events prevented (20% the baseline scenario). variables by changing the values from the minimum to their maximum. Figure 101 shows the effect on the economic indicators (B/C ratio and Total NPV) caused by varying the percent- Due to the high value of the EIRR in the baseline scenario age of faults events prevented from 10% to 25%. no sensitivity has been performed on the discount rate. Volume 2: Cost-Benefit Analysis 203 FIGURE 98: DGA SENSITIVITY ANALYSIS Source: Authors FIGURE 99: DTCR SENSITIVITY ANALYSIS Source: Authors 204 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 100: GIS SENSITIVITY ANALYSIS Source: Authors FIGURE 101: POWER QUALITY MONITORING AND METERING DATA ACQUISITION SYSTEMS SENSITIVITY ANALYSIS Source: Authors I. Risk Analysis I.1 Key Points Summary It is crucial to evaluate all the risks related to each Smart Grid initiative in order to “measure” the odds of success In this chapter the risks analysis has been performed in or failure. order to collate all the key information for the final prioriti- zation of the initiatives and the refinement of Smart Grid The risk assessment process is comprised of different roadmap. steps, which from the context awareness and risks cat- egories definition leads to identifying a risk scale and Towards this end, all the key parameters required to eval- likelihood thus leading to a risk assessment of the Smart uate the risks are defined in terms of: Grid initiatives. a. Risk categories; This paragraph ‘I.2’ aims to define all the relevant param- eters for evaluating the risks. In particular it identifies: b. Risk impact; and c. Risk likelihood. a. Risk categories. It is crucial to understand all the possible risk sources and group them in an appro- Based on these parameters a risk assessment has been priate way; carried out for all the Smart Grid initiatives, weighting the b. Risk impact scale. It is fundamental to measure risk impact with the related risk likelihood and so mea- the impact of the risks on the Smart Grid road- suring the chance of failure of each solution. In particu- map and on return on the investment of each lar this analysis highlights those solutions that carry a initiative; greater probability of failure (like FLS and DGA) in terms of “Time” , “Stakeholders’ actions” and “Investment c. Risk likelihood scale. It is fundamental to mea- uncertainty” . sure the odds of success and failure. Finally, the underlined risks cannot be fully eliminated, Having an understanding of the key elements that could but they can be mitigated through the application of impact on the Smart Grid roadmap is crucial to estab- some ameliorating actions suggested in this chapter. lishing the context,. in order to facilitate the risk assess- ment, the various sources of risk can be grouped into The identified risks, related mitigating actions together categories as follows: with the technical reasons (described in the technical analysis report) as well as the economic results of the a. Time. Both the starting time and the pace of Cost-Benefit Analysis (performed in the previous chap- installation of each Smart Grid initiative must be ters) have together helped to decide the final prioritiza- considered carefully. In some cases if the return tion of Smart Grid initiative carried out in chapter ‘J’. of an investment is postponed the correspond- ing benefits may not cover the costs. This is even more apparent when the initiative postponed is I.2 Definition of risks categories, an enabling technology for other stages of the roadmap. scale and likelihood b. Stakeholders’ actions. The behavior, strategy The risk assessment process is an essential step before and policies of the internal and external stake- defining the final prioritization of the initiatives in the holders will affect the roadmap implementation. Smart Grid roadmap. As for all large-scale programs, the In particular the level of commitment from the Vietnamese Smart Grid roadmap will face various risks institutions and the extent to which their pro- that cannot be fully eliminated, but that can be mitigated cesses and attitudes hinder the progress of the through the systematic application of management poli- roadmap will have to be considered. cies, procedures and practices. c. Investment uncertainty. The CBA performed in the previous chapters has identified some 205 206 Smart Grid to Enhance Power Transmission in Vietnam indicators that define the uncertainty of the baseline scenario causes a big change in the investment for each Smart Grid initiative. In par- economic parameters thus making the proj- ticular these indicators are: ect non-viable. On the contrary, if the project remains viable despite a big change in its main i. EIRR: A higher EIRR indicates a low risk invest- variables the risk is considered low. ment. That is, EIRR shows by how much the discount rate or risk probabilities have to rise Table 70 summarizes the possible risks source consid- in order to eliminate the present value of this ered for each risk categories. investment. The various sources of risks under each category can ii. Sensitivity analysis results: Sensitivity anal- have different levels of impact. So, before performing the ysis involves recalculating project outcomes risk assessment, it is helpful to assume a risk scale to (NPV, B/C ratio) for different values of the evaluate the impact of the identified risk to the Smart major variables and combinations of variables. Grid initiatives. Table 71 defines the risk impact scale that The risk of the project is considered high if a is used in “Risk assessment of Smart Grid initiatives” small change in a variable with respect to the described in the next paragraph ‘I.3’. TABLE 70: RISK CATEGORIES Risk category Possible risks source considered • The delay to the implementation process of an initiative that directly and consistently affects the return on the investment. Time • The delay in the implementation process of an initiative that directly affects the success of the Smart Grid roadmap. • The institutional level/process level capabilities and willingness to address risks. • The commitment from the authorities to implement the roadmap. Stakeholders’ actions • The deployment resource for a Smart Grid initiative is downsized. • Inefficient exploitation of a Smart Grid initiative. • EIRR determines the level of the investment uncertainty and so a low value implies a high implementation risk. Investment uncertainty • Sensitivity of a key parameter of a Smart Grid initiative can alter its benefits. A change in the project viability as a consequence of a small change in the parameter indicates a high implementation risk. Source: Authors TABLE 71: RISK IMPACT SCALE Level number Impact Level Description 1 Insignificant No real business impact - may have a low financial or time line impact but no change relative to baselines. 2 Minor Inconvenient - no significant impact, can be immediately contained but no change relative to baselines. 3 Moderate Medium to high impact - may have a medium financial or time line impact but no change relative to baselines. 4 Major Extensive impact - especially to the business, high to major financial loss and a compelling need to change go live dates. Change relative to baselines. 5 Catastrophic Huge impact - could result in the project being terminated with commensurate financial loss. Change relative to baselines. Source: Authors Volume 2: Cost-Benefit Analysis 207 TABLE 72: RISK LIKELIHOOD SCALE Level number Likelihood level Description 1 Rare The risk may occur only in exceptional circumstances 2 Low The risk could occur at some time 3 Moderate The risk should occur at some time 4 High The event will probably occur in most circumstances 5 Almost Certain The event is definitely expected to occur in most circumstances Source: Authors To perform the risk assessment of each Smart Grid initia- them can affect the predicted outcomes the cost-benefit tive it is important to weight the impact of each risk using analysis. a scale that indicates the probability of its occurrence. Therefore, each risk is characterized not only by the level The risk likelihood of an increase in the discount rate of impact but also by the likelihood of it occurring. Table is considered moderate while the impact of this event 72 defines the risk likelihood scale that is used in “Risk depends on the specific initiative and has been estimated assessment of Smart Grid initiatives” descripted in the using the EIRR (low value of this parameter equates to a next paragraph ‘I.3’. high implementation risk). In the next paragraphs (from ‘I.3.1’ to ‘I.3.10’) the specific I.3 Risk assessment of Smart Grid risks of each initiative are investigated with an explanation initiatives for their characterization in terms of likelihood and impact. In this paragraph the risk assessment is concluded and I.3.1 Substation Automation System (SAS) all the key information for the final prioritization of the initiatives is collated and used to refine the Smart Grid It is possible that there is a “Delay in the installation of roadmap. For each Smart Grid initiative the possible risks new substations equipped with SAS” but even though are evaluated in terms of both likelihood and impact. the likelihood of this happening is quite high the risk of reduced benefits is low because the return on invest- Table 73 summarizes all the risks that have been consid- ment time is relatively short. ered for each initiative: Further, the possibility of the “Initiative being downsized” a. The green cells indicate “Time” category risks; is very low because the SAS project has already reached a high level of deployment in Vietnam. However, if this were b. The violet cells indicate “Stakeholders’ actions” to happen it would mean fewer substations installed with category risks; SAS and thus a smaller value for the reduction of EMS. c. The orange cells indicate “Investment uncer- Ultimately the reduction of EMS is directly proportional tainty” category risks. The risks are reported as to the number of substations installed with SAS. a variation with respect to the baseline scenario, which represents the best case scenario. The “Decrease of Energy Not Served value” with respect to the baseline scenario has a medium financial impact The increase in the discount rate with respect to the as can be seen in the preceding sensitivity analysis (para- assumption made in the baseline scenario is an external graph ‘H.2’). ENS value per MWh could decrease by 30% risk for all the projects investigated. In fact, the discount without affecting the economic viability of the SAS imple- rate adopted for the assessment of the economic viabil- mentation but would reduce the NPV and B/C ratio. The ity of the initiatives can be influenced by many factors likelihood of this happening is considered moderate, as (inflation rate, default risk, interest rate, macroeconomic the value adopted in the reference scenario is a conser- growth, exchange rate, etc.) and a variation of one of vative estimate. 208 Smart Grid to Enhance Power Transmission in Vietnam TABLE 73: SMART GRID APPLICATION RISK ASSESSMENT Smart Grid Initiative Risk Likelihood Impact Delay in the installation of new substations equipped with SAS Moderate (3) Minor (2) Initiative downsized Very low (1) Major (4) Increase in the discount rate Moderate (3) Minor (2) SAS Decrease of Energy Not Served value Moderate (3) Moderate (3) Decrease of average value of annually ENS reduction per substation Low (2) Moderate (3) equipped with SAS Delay in PMU installation Moderate (3) Minor (2) Delay in developing application based on WAMS Moderate (3) Major (4) Reduction in the number of installed PMUs Moderate (3) Minor (2) WAMS Inefficient development of applications based on WAMS data Moderate (3) Major (4) Increase in the discount rate Moderate (3) Insignificant (1) Decrease of Energy Not Served value Moderate (3) Minor (2) Decrease of the percentage of fault events prevented Moderate (3) Minor (2) Delay in sensor installations Moderate (3) Minor (2) Delay in developing remote monitoring center Moderate (3) Major (4) Reduction in the number of installed sensors Moderate (3) Minor (2) Lightning Inefficient exploitation of the system in daily operation Moderate (3) Major (4) Location System Increase in the discount rate Moderate (3) Insignificant (2) Decrease of Energy Not Served value Moderate (3) Minor (2) Decrease of the percentage of fault events prevented Moderate (3) Minor (2) Delay in the installation process Moderate (3) Minor (2) Inappropriate choice of installation sites Moderate (3) Major (4) The selected sites are only temporarily adequate Moderate (3) Major (4) SVC Increase in the discount rate Moderate (3) Major (4) Decrease of Energy Not Served value Moderate (3) Moderate (3) Decrease of the percentage of fault events prevented Moderate (3) Moderate (3) Delay in the installation process Moderate (3) Minor (2) Low power factor in operation of the HVDC link Low (2) Catastrophic (5) HVDC Increase in the discount rate Moderate (3) Insignificant (2) Decrease of power losses cost Moderate (3) Major (4) Delay in the installation process Moderate (3) Minor (2) Initiative scope downsized Low (2) Major (4) Increase in the discount rate Moderate (3) Major (4) FLS Decrease of outage time duration reduction Moderate (3) Catastrophic (5) Decrease of Energy Not Served value Moderate (3) Major (4) Decrease of percentage of lines with faults monitored with the FLS Moderate (3) Major (4) Delay in the transformer installation process Moderate (3) Insignificant (1) Initiative scope downsized Low (2) Minor (2) DGA Increase in the discount rate Moderate (3) Major (4) Decrease of average cost of a transformer fault Moderate (3) Catastrophic (5) Delay in the equipment installation process Moderate (3) Minor (2) Dynamic Inefficient exploitation of the system in daily operation Low (2) Major (4) Thermal Circuit Increase in the discount rate Moderate (3) Insignificant (1) Rating Decrease of the number of lines with deferred reconductoring Moderate (3) Minor (2) Decrease of number of years of deferred investment Moderate (3) Minor (2) Delay in the implementation process Low (2) Minor (2) Exploitation of the initiative in a limited number of contexts Low (2) Moderate (3) GIS Increase in the discount rate Moderate (3) Minor (2) Decrease of operation and maintenance cost savings for SAS application Moderate (3) Minor (2) Power quality Delay in the implementation process Moderate (3) Minor (2) monitoring and No proper consideration of the regulatory implications Moderate (3) Major (4) Metering Data Increase in the discount rate Moderate (3) Insignificant (1) Acquisition Decrease of Energy Not Served value Moderate (3) Minor (2) Systems Decrease of the percentage of fault events prevented Moderate (3) Minor (2) Source: Authors Volume 2: Cost-Benefit Analysis 209 The “Decrease of average value of annual ENS reduc- It is worth pointing out that “Stakeholders’ actions” tion per substation equipped with SAS” with respect to risks, a ”Weak exploitation of the system in daily oper- the baseline scenario has a medium financial impact. The ation” carries far more risk to the success of the proj- sensitivity analysis (paragraph ‘H.3’) demonstrates that ect than does a “Reduction in the number of installed NPV remains positive even though the ENS reduction per sensors” . substation falls to 50% of the best estimation. The “Decrease of Energy Not Served Value” with respect to the baseline scenario has no significant financial I.3.2 Wide Area Monitoring System (WAMS) impact as can be seen from the sensitivity analysis (para- Regarding WAMS, the “Time” risks can be derived graph ‘H.2’). ENS value per MWh could decrease by 30% from both ”Delay in PMU installation” and from “Delay without affecting the economic viability of the LLS imple- in developing applications based on WAMS” and they mentation but would slightly reduce NPV and B/C ratio. can be considered equally likely. While the first cause a The likelihood of this is moderate as the value adopted in reduction in the observability of the network the second the reference scenario is a conservative estimation. one causes a consistent reduction in the benefits and thus has a higher impact. Without a complete and effec- The “Decrease of the percentage of fault events pre- tive development of monitoring applications based on vented” with respect to the baseline scenario has no PMU data no benefits will be achieved. significant financial impact. As can be seen from the sen- sitivity analysis (paragraph ‘H.5’) a 60% reduction of the It is worth pointing out that in the table under “Stake- avoided faults would result in a 15% decrease in the NPV, holders’ actions” risks, a ”An inefficient development which would still remain positive. The probability of this of applications based on WAMS” carries far more risk to event is moderate. the success of the project than does a “Reduction in the number of installed PMUs” . I.3.4 Static Var Compensator (SVC) The “Decrease of Energy Not Served value” with respect The process of selecting the right sites for the installa- to the baseline scenario has no significant financial tion of the SVCs could delay the entire implementation impact as can be seen in the sensitivity analysis (para- process. If this “Time” risk is less than 2 years, the delay graph ‘H.2’). ENS value per MWh could decrease by 30% will have a minor impact as it only delays the return on without affecting the economic viability of the WAMS investment. However, the “Stakeholders’ actions” risks implementation but would reduce the NPV and B/C ratio. are more critical. The “No proper choice of the installation The likelihood of this event is moderate as the value used sites” in conjunction with “The selected sites are only in the reference scenario is a conservative estimation. temporarily adequate” could completely compromise the investment in such equipment. The “Decrease of the percentage of fault events pre- vented” with respect to the baseline scenario has no sig- The “Decrease of Energy Not Served Value” with respect nificant financial impact as can be seen in the sensitivity to the baseline scenario has a medium financial impact analysis (paragraph ‘H.4’). The effect of a 50% reduction as can be seen from the sensitivity analysis (paragraph of the avoided faults is just a 10% decrease in the NPV ‘H.2’). ENS value per MWh could decrease by 30% with- which in any case remains strongly positive. The probabil- out affecting the economic viability of the SVC implemen- ity of this event is moderate as the value adopted in the tation but would reduce NPV and B/C ratio. The likelihood reference scenario is a realistic estimation. of this event is moderate as the value adopted in the reference scenario is a conservative estimation. I.3.3 Lightning Location System (LLS) The “Decrease of the percentage of fault events pre- As with WAMS, the “Time” risks can be derived from vented” with respect to the baseline scenario has a both ”Delay in sensors installation” and from “Delay in medium-high financial impact as can be seen from the developing remote monitoring center” and they are both sensitivity analysis (paragraph ‘H.6’). A 50% decrease equally likely. The real added value of LLS (as for WAMS) in the avoided faults would cause a negative NPV and is the availability of the data in a remote control center threaten the economic viability of the project. The likeli- so the second type of delay has a higher impact. Without hood of this event is moderate as the value adopted in the full development of a monitoring center for collecting the reference scenario is a conservative estimation. and processing data no benefits will be achieved. 210 Smart Grid to Enhance Power Transmission in Vietnam I.3.5 High Voltage Direct Current (HVDC) The “Decrease of percentage of lines with faults moni- technology tored with the FLS” with respect to the baseline sce- nario has an extensive impact assessed as major to high Similarly to SVC, the site selection process for the installa- risk of financial loss. The sensitivity analysis (paragraph tion of these devices could delay the project significantly. ‘H.8’) demonstrates that NPV becomes negative when The cost-benefit analysis performed on HVDC technol- the number of lines with faults equipped with a FLS ogy demonstrates that a delay in the installation will in decreases by 10% when compared with the baseline. turn delay the return on investment. This is classified a minor risk for the implementation of this technology. I.3.7 On-line Dissolved Gas-in-oil Analysis It is worth noting that once a HVDC link is in place it is (DGA) important to the return on investment that it does not In this case the installation of the DGA monitoring device suffer from a “Low power factor in operation on the is connected with the installation of a new transformer, HVDC link” as this will have a detrimental impact on the so both benefits and costs will be equally delayed. The benefits of the initiative. impact of such a risk can be considered negligible. The “Decrease of power losses cost” with respect to Similarly, if the initiative is downsized by a decision not the baseline scenario has a significant impact and has to equip a significant number of the new transformers been assessed as a major to high risk of financial loss with DGA monitoring devices, the initiative will continue as can be seen from the sensitivity analysis (paragraph to be beneficial. The overall benefit of the initiative is a ‘H.7’). The impact of a 20% reduction in the energy cost simple sum of the single benefits obtained from each will represent a financial loss to the project (i.e. a nega- transformer protected. tive NPV and a B/C ratio less than one). The probability of this event has been considered moderate as the value The “Decrease of the average cost of a transformer fault” adopted in the reference scenario is a realistic estimation. with respect to the baseline scenario has a huge impact and could result in the project not being viable as can be I.3.6 Fault Locator System (FLS) seen from the sensitivity analysis (paragraph ‘H.9’). The impact of a 10% reduction in the cost of a transformer A delay in the FLS installation process has a minor impact fault will mean a financial loss for the initiative as a whole because it only delays the return on the investment. (i.e. a negative NPV and a B/C ratio less than one). The However, a reduction of the lines protected (“Initiative probability of this event is moderate as the value adopted downsized”) proportionally decreases the ability to pro- in the reference scenario is a realistic estimation. tect the critical lines with FLS devices and consequently reduces the benefit of this initiative. While the impact is significant, the risk that the FLS initiative is downsized I.3.8 Dynamic Thermal Circuit Rating (DTCR) is quite low because NPT has already decided to equip The time window for a return on investment in a DTCR about 70 lines with these devices. solution is quite large so any delays in the installation process will not risk the benefits. On the other hand, an The “Decrease of Energy Not Served value” with “Inefficient exploitation of the system in daily operation” respect to the baseline scenario has an extensive impact will utterly compromise the investment in this solution. assessed as major to high risk of financial loss. As can be However, a well-designed project for the development of seen from the sensitivity analysis (paragraph ‘H.2’) NPV dynamic rating will do much to mitigate if not entirely becomes negative if the ENS value is 15% lower than the preclude this risk. baseline scenario. The “Decrease of the number of lines with deferred The “Decrease of outage time duration reduction” with reconductoring” with respect to the baseline scenario respect to the baseline scenario has a huge impact and has a no significant impact as can be seen in the sen- could result in the project not being financially viable sitivity analysis (paragraph ‘H.10’). The number of lines as can be seen from the sensitivity analysis (paragraph could be reduced by 50% (in this case two instead of ‘H.8’). A 10% decrease in the reduction of outage time four) without affecting the economic viability of the duration relative to the baseline compromises the viabil- DTCR implementation but will result in a slightly lower ity of the initiative (i.e. causes a negative NPV and a B/C NPV and B/C ratio. The likelihood of this event is moder- ratio less than one). The likelihood of this event is mod- ate as the value adopted in the reference scenario is a erate as the value adopted in the baseline scenario is a realistic estimation. conservative estimation. Volume 2: Cost-Benefit Analysis 211 The “Decrease of number of years of deferred invest- has a no significant financial impact as can be seen from ment” with respect to the baseline scenario has no signif- the sensitivity analysis (paragraph ‘H.12’). The effect icant financial impact. The sensitivity analysis (paragraph of a 50% reduction of the faults avoided is just a 5% ‘H.10’) indicates that NPV remains high and positive even decrease in the NPV, which will still remain positive. The though the number of years of deferred investment is probability of this event is moderate as the value adopted assumed to be three instead of five (best case scenario). in the reference scenario is a realistic estimation. I.3.9 Geographic Information Systems (GIS) I.4 Risk Map Delaying the implementation of this solution does not present a particular risk to the Smart Grid initiative. The impact of each risk can be multiplied by a weight- However, it provides vital geographical data that can be ing value to calculate its likelihood. The risks associated exploited and shared by a large number of applications with each initiative can be compared based on assuming (SAS, WAMS, etc.). Thus delays or even “Exploitation of a high-risk scenario for each. the initiative in a few contexts” will reduce the potential benefits of this initiative. This comparison is graphically depicted in Figure 102 below. Each Smart Grid initiative has been positioned on The “Decrease of operation and maintenance cost sav- a graph where the abscissa (x axis) is the risk impact ings for SAS application” with respect to the baseline while the ordinate (y axis) maps the risk likelihood. The scenario has a no significant financial impact. The sensi- color shade of each Smart Grid initiative identifies the risk tivity analysis (paragraph ‘H.11’) shows that while a 50% category where: reduction in the SAS O&M savings will decrease the NPV by 70%, it will still remain positive. The likelihood of this a. Green stands for the “Time” category risk; event is moderate. b. Violet stands the “Stakeholders’ actions” cat- egory risk; I.3.10 Power quality monitoring and Metering c. Orange stands for the “Investment uncer- Data Acquisition Systems tainty” category risk. Again, a delay in the implementation of these two applications does not have any particular reper- FIGURE 102: RISK MAP cussions. However, if “No proper consideration of the regulatory implications” occurs, the finan- cial investment could be lost. As stated in the technical report, for the successful exploitation of these two initiatives it is vital that a suitable and clear regulatory policy focused on the relation- ship with the electricity generation function be developed in order to ensure maximum synergy under critical conditions. The “Decrease of Energy Not Served value” with respect to the baseline scenario has no sig- nificant financial impact as can be seen from the sensitivity analysis (paragraph ‘H.2’). ENS value per MWh may decrease by 30% without affect- ing the economic viability of the implementation but will result in a slightly lowered NPV and B/C ratio. The likelihood of this event is moderate as the value adopted in the reference scenario is a conservative estimation. The “Decrease of the percentage of fault events prevented” with respect to the baseline scenario Source: Authors 212 Smart Grid to Enhance Power Transmission in Vietnam I.5 Risk mitigation actions and procedures as suggested in Table 74 This table lists some recommendations for the various risk categories While the risks identified for each initiative cannot be fully (green for “Time”, violet for “Stakeholders’ actions” and eliminated, they can be mitigated by appropriate actions orange for “Investment uncertainty”). TABLE 74: RISK MITIGATION ACTIONS Smart Grid Initiative Mitigation action Link the final commissioning of new substations with the complete commissioning of their SAS equipment. Manage the gap between the roadmap and real installation pace. SAS Streamline the SAS automation installation process to target the most critical areas first. Monitor the performance of the already implemented SAS for a better estimation of the ENS saved and a reduction of the investment uncertainty. Expedite the development of the remote control center. Focus investments on developing applications based on WAMS data. WAMS Streamline the Phase Measurement Unit installation process to target the most critical lines. Monitor the performance of the installed PMUs for a better estimation of the faults that can be avoided and a reduction of the investment uncertainty. Expedite the development of the remote control center. Lightning Focus investments on developing applications fed by LLS data and carry out adequate training for the control room Location System operators to exploit LLS information. Optimize the positioning of the sensors in order to cover the whole network. Engage with the planning department to choose optimal installation sites. Re-locatable SVCs can easily solve the problem of site selections that are either not the best fit for purpose or those sites that are only temporarily fit for purpose. SVC Develop a planning activity for the SVC initiative in order to improve the reactive compensation starting with the most critical areas. Use the first implementations for data collection and reduction of investment uncertainty. Engage with the planning department to choose optimal installation sites. Develop a proper system operation strategy to fully exploit the HVDC links. HVDC Perform electricity market studies for the medium and long term in order to better estimate the cost of energy and investigate potential profitable connections with foreign countries. Expedite the installation for the most critical lines. Manage the gap between the roadmap and real installation pace. FLS Optimise the planning activities in order to implement the FLS on those lines with the highest maintenance cost. Monitor the already implemented FLS’s for a better estimation of the average reduction outage time duration that is possible with this initiative. Align the final commissioning of new transformers and their DGA equipment. Manage the gap between the roadmap and real installation pace. DGA Optimize the planning activities in order to implement the DGA on those transformers with the highest cost of repair and those with the highest fault probability. Monitor the already implemented DGA’s for a better estimation of the benefits that can be obtained with this initiative. Expedite the installation on the most critical lines. Dynamic Develop a proper system operation strategy to full exploit the dynamic rating initiative. Thermal Circuit Develop a planning activity for the DTCR initiative in order to improve the transfer capacity of the lines starting with the Rating most critical areas. Place GIS on the critical path for the installation of those applications that will benefit from it. Evaluate the added value of GIS functionality for the largest number of applications. GIS Develop an effective software application and user interface in order to maximize the benefit of the GIS initiative in terms of O&M reduction. Power quality Expedite the installation on the most critical areas. monitoring and Develop a clear regulatory policy focused on the relationship with the electricity generation function to ensure maximum Metering Data synergy under critical conditions. Acquisition Develop a planning activity for the initiative in order to reduce the unserved energy starting with the most critical areas. Systems Source: Authors J. Final Prioritization J.1 Key Points Summary f. Wide Area Monitoring System starts in the short term while the complete rollout concludes in the The aim of this chapter is to perform the final prioritiza- medium term. The prioritization of the main lines tion of all the Smart Grid initiatives and to position them and areas are in the short term; on a timeline, setting the best starting point for the g. Substation Automation System, including remote solutions and proposing suitable elapsed times for their control centers building/upgrade, already started development. in the short term will continue with the rollout until completion in the medium term; This prioritization is a refinement of the Vietnamese Smart Grid roadmap and includes a phased implementa- h. Power quality monitoring system and Metering tion plan. This analysis factored in the following for each Data Acquisition System start in the short term Smart Grid initiative: with the full rollout expected in the medium term; i. High Voltage Direct Current technology with the a. The technical reasons described in technical anal- pre-requisite preliminary studies and activities in ysis report; the short term and the finalization of the medium b. The economic results of the Cost-Benefit Analy- term; and sis performed in the previous chapters (from ‘D’ j. On-line-Dissolved Gas-in-oil Analysis, already to ‘H’); and started in the short term, will be completed in c. The risks and related mitigation actions investi- the long term. gated in the previous chapter. J.2 Smart Grid initiatives time As in the technical analysis report three different time scales are considered in the development of the initiatives: positioning a. Short term (within next 5 years); In order to refine the final prioritization of the Smart Grid initiatives the timeline positioning suggested in the tech- b. Medium term (within next 10 years); and nical analysis has been selected as a starting point. The c. Long term (within next 15 years). positioning of the various initiatives has factored in the economic results of the Cost-Benefit Analysis and the This prioritization process has assigned the following: previously assessed risks. a. Geographic Information Systems positioned in In particular: the short term; a. The positioning of an application is confirmed b. Dynamic Thermal Circuit Rating positioned in the at its current point on the timeline if it is not con- short term; tradicted by its economic and risk indicators; c. Lightning Location System positioned in the short b. The positioning of an application is brought term; forward from its current point on the timeline if d. Fault Locator System with recommended prelimi- its economic and risk indicators are compelling; nary activities and their finalization in the short term; and e. Static Var Compensator with some preliminary c. The positioning of an application is post- activities in the short term with finalization of poned from its current point on the timeline if its the expected installed capacity at the start of the economic and risk indicators are unfavorable. medium term; 213 214 Smart Grid to Enhance Power Transmission in Vietnam Based on these premises the following applications have indicators (EIRR: 164% and B/C ratio: 6.89) are been confirmed for implementation in the short-term: compelling reasons to investment in this solu- tion. All the risks associated with this initiative a. Wide Area Monitoring System. This applica- can be mitigated by focusing the investments on tion is recommended to begin in the short term developing applications fed by LLS data and car- with the complete rollout being concluded in rying out commensurate training for the control the medium term. The prioritization of the main room operators to exploit LLS information. As lines and areas are positioned in the short term. stated in the technical analysis report, the basic As stated in the technical analysis report WAMS implementation phases are: is a solution that ”enables” some of the others i. The evaluation of all the available technologies (e.g. Dynamic Thermal Circuit Rating) and will with respect to the specific needs of all the help solve a large number of issues (e.g. voltage transmission utility functions that could ben- and transient stability, defense plan deficiencies, efit from such a system; etc.); so its development must start as soon as possible. Furthermore, WAMS’s economic indi- ii. The evaluation of the number of sensors cators are very positive (EIRR: 204% and B/C needed to cover the country with homoge- ratio: 17.82) and the initiative does not present neous and high detection performance, event unconquerable risks if the WAMS based applica- discrimination, location accuracy and 24/7 tions are properly developed. The implementation availability; activity is comprised of: iii. The evaluation of the orography and conse- i. Development of a remote control center; quently the identification of the ideal locations for the sensors (taking account of factors ii. Development of a strategy for the location of like electromagnetic noise, structural shields, PMUs; physical security, terrain, telecommunication iii. Installation and cabling of PMUs; links, etc.); iv. Development and implementation of WAMS iv. Obtaining contractually binding agreements based applications; and with local site owners wherever necessary; v. Integration of information and results obtained v. The execution of all civil and electrical works from WAMS based applications and daily sys- at the identified sites including power and tele- tems operation. communications cabling if needed; b. Substation Automation System. This is a NPT vi. The implementation of an Operational Center project that has already reached a significant level provided with specific power and telecommu- of development. The initiative, which includes the nication schematics and a server for data anal- building/upgrading of remote control centers, has ysis where all sensor data will be received, already started and is positioned, by default, in processed and stored; the short term but its complete rollout will not vii. The fine tuning of LLS (using the most immedi- conclude until the medium term. The economic ately available data), implementing site correc- indicators are positive and the assessed risks can tions of detection parameters and thresholds be successfully mitigated with an efficient sub- where needed; and station commissioning policy and management of the gap between the roadmap and real instal- viii. The assignment of dedicated and properly lation pace. The implementation activity includes trained staff. the installation and the commissioning of new d. Power quality monitoring system and Meter- substations equipped with SAS. ing Data Acquisition System. These initiatives c. Lightning Location System. This initiative has are prioritized in the short term but their complete been positioned in the short term. The technical rollout will not conclude until the medium term. analysis had considered this as a short-term solu- Both these initiatives have been positioned in tion due to the criticality of the lightning problem the short-term because their total cost (CAPEX: in Vietnam. The intelligence of the system is sup- $301,500 and OPEX: $97 ,200) is amongst the plied by the location system and not the arrest- lowest of all the initiatives while the economic ers (which are dumb devices). The economic indicators are the most compelling (EIRR: 797% Volume 2: Cost-Benefit Analysis 215 and B/C ratio: 39.26). In order to mitigate the fully exploits the dynamic rating initiative. The assessed risks before beginning the deployment implementation activity is basically comprised of: of these initiatives it is important to carefully con- i. Careful selection of the lines to be monitored; sider all the regulatory aspects. The implementa- tion activity is basically comprised of: ii. Choice of the monitoring devices; i. Careful analysis of all the regulatory aspects; iii. Development of algorithms and procedures for real-time temperature estimation; and ii. Development of a remote control center; iv. Integration of information and results obtained iii. Development of a strategy for the location of from Dynamic Thermal Circuit Rating and daily devices; system operations. iv. Installation and cabling of devices; and g. Static Var Compensator. Some preliminary v. Implementation of software tools for process- activities are required to be performed in the short ing data: term while the roll-out of the total capability has been positioned at the beginning of the medium e. Geographic Information Systems. This is posi- term. Such preliminary activity is highlighted in tioned in the short term. As stated in the technical the final time positioning of the Smart Grid initia- analysis, the prior development of other systems tives. Further, the risk analysis has revealed that like SAS or WAMS will be important to enable the as Vietnam’s power network is growing rapidly it implementation of this solution which is likely to would significantly complicate the choice of the support the largest number of applications and locations of SVC devices. To mitigate such risks delivering significant benefits to the enterprise. relocatable SVCs have been suggested which Given that the total cost (CAPEX: $175,000 and will allow the flexibility of temporary installations OPEX: $262,500) is much lower than for most while retaining the investment despite future of the other systems and the economic indica- growth. Even though the total cost is quite high tors are positive (EIRR: 48% and B/C ratio: 3.61) (CAPEX: $31,500,000 and OPEX: $1,255,500) it makes sound economic and technical sense to the economic indicators are good (EIRR: 14% implement this system in the short term. Further, and B/C ratio: 1.21) this investment makes good no particular risks have been highlighted. The economic sense. Furthermore, the SVC initia- implementation activity is basically comprised of: tive achieves significant benefits both in terms i. Careful selection of all the applications that of integration of renewable energy generation would benefit from this initiative; and in terms of blackout prevention. Moreover, the criticality of the voltage stability issues ii. Development of procedures and strategies to in the Vietnamese [19] transmission network store and share GIS data; and argues against delaying this measure for too long iii. Implementation of software tools for process- because it may jeopardize system security and ing and displaying data. availability. The plan to start its full implementa- tion in the latter part of the short-term is likely the f. Dynamic Thermal Circuit Rating. This initiative right choice as it will allow a suitable time for the has been positioned in the short term. The tech- detailed feasibility study phase. Therefore, the nical analysis had originally positioned this initia- already planned devices can be installed but the tive in the long term on the basis that it would be full deployment of the initiative has to be posi- better to wait for the current rapid growth rate of tioned for the mid-term. the transmission network to stabilize in order to leverage this application on a large scale. How- h. Fault Locator System. This initiative is posi- ever, since the CBA has revealed that its eco- tioned in the short-term. The economic indicators nomic indicators are extremely positive (EIRR: are lower than for other applications (EIRR: 13% “All positive cash flows” and the B/C ratio: 35.11), and B/C ratio: 1.17) and the investment is quite it would make both technical and financial sense high (CAPEX: $8,400,000). Also the risk assess- to implement this technology in the short term. ment has highlighted that the “Investment uncer- The related risks can be easily mitigated by devel- tainty” has the highest value for this initiative. oping a rigorous system operation strategy that On the other hand, the NPT project is already 216 Smart Grid to Enhance Power Transmission in Vietnam underway and is quite independent from all the implementation, if considered feasible following other initiatives. Therefore, the recommendation the findings of the study, should be positioned is to evaluate the real benefits of this technology in the medium term. However, at the outset it on a small number of lines and then decide if it is can be safely assumed that the economic indi- worth deploying across the estate. For this rea- cators are good with regard to the technology son only a pilot program for FLS benefits evalu- application per se if not the line itself. In fact, ation has been positioned in the short term. If in even if the total incremental costs are very high the next few years the cost of this technology (CAPEX: -$16,800,000 and OPEX: $118,098,000), decreases its current positioning can be reconsid- the EIRR has “All positive cash flows” the B/C ered and, if required, brought forward. Finally, the ratio is 1.56. The economic indicators in fact do implementation activity is basically comprised of: not consider several other strategic and technical benefits that if included would likely make a very i. Careful selection of the lines to be monitored; strong case for the development of HVDC tech- ii. Installation and wiring of the devices; and nology in Vietnam. On balance it is worth plan- ning the development of this technology because iii. Development of algorithms and procedure for it could prove useful for both interconnections the exploitation of FLS data. with neighboring countries [19] and for long links i. On-line Dissolved Gas-in-oil Analysis. CBA (e.g. 500kV link with lengths greater than 700km) results show that the investment is less attrac- connecting the Northern and Southern parts of tive in economic terms than other initiative Vietnam. Furthermore, the HVDC technology is (EIRR: 12% and B/C ratio: 1.13) and the total cost perhaps the best Smart Grid initiative in terms of is quite high (CAPEX: $77 ,592,000 and OPEX: integrating with new variable renewable genera- $3,343,245). But even if the high cost of moni- tion. In fact the increased transfer capacity and toring devices would make this solution a high- active power control are fundamental benefits risk economic strategy, it is worth to consider which would enable the installation of wind or the average lifetime of this type of transformers solar power plants carrying the variable gener- (about 25 years) and to start investing in this tech- ated energy to the load areas and balancing the nology in the short term. The transformers’ fault natural fluctuation of renewables. The real imple- risk in fact is not positioned in the near future mentation of HVDC is reliable only in the medium but it is widespread in all their lifetime, which is term since this initiative requires quite a long pre- longer that the time horizon considered for the liminary feasibility study probably lasting about 4 investment. As described in the technical analysis years. Such preliminary activity is highlighted in (see Report 1, paragraph ‘F .11’), it is fundamental the final time positioning of the Smart Grid initia- to start monitoring transformers as soon as pos- tives. After this study phase the real implementa- sible in order to effectively use the stored data for tion activity (comprised of the construction of the an accurate diagnostic in the future (15-20 years) HDVC line/s) can start, which typically last, based on aged transformers, and so fully exploit DGA on the consultant’s experience, about 4 years. technology. Therefore the benefits of this initia- The positioning of an initiative at a particular point on tive are achievable only if the device installation the timeline implies a starting point. It happens that the starts in the short term. implementation process of some solutions will extend While in the medium-term are positioned: for 5 years or more. For example the SAS development process is already underway and it is considered a short- a. High Voltage Direct Current technology. In term initiative, although the complete installation will order to assess the economic feasibility of the not be concluded for at least ten years. Equally the full HVDC technology, the incremental costs of a new implementation of WAMS, Power quality monitoring sys- 800 km DC link compared with the cost of an AC tem and Metering Data Acquisition System, which are 500 kV solution have been estimated. It has been closely linked to the installations of new substations, will assumed that the original planning for this instal- be completed in the same ten-year time interval. lation only considered the technical benefits of the AC line rather than of the strategic benefits of Figure 103 shows the final timeline positioning of the the line itself to the wider network. This initiative Smart Grid initiatives and provides the phased implemen- requires preliminary studies and activities that tation plan for the Vietnamese roadmap. should be conducted in the short term, while the FIGURE 103: FINAL TIME POSITIONING OF SMART GRID INITIATIVES Source: Authors Volume 2: Cost-Benefit Analysis 217 References [1] V. Giordano, I. Onyeji, G.Fulli, M. S. Jiménez, C. [13] M. Bernardi, C. Giorgi, V. Biscaglia, “Medium voltage Filiou, ”Giudelines for conducting a cost-benefit line faults correlation with lightning events recorded analysis of Smart Grid projects”, JRC, REFERENCE with the Italian LLP system CESI-SIRF” , Proc. 24th REPORTS, 2012. International Conference on Lightning Protection, Birmingham-UK, 1998, vol.1, pp. 187-192. [2] http://www.vir.com.vn/blackouts-prompt-call-for- powerful-measures.html [14] https://library.e.abb.com/public/9858b1cd9bd8086 08325778f002bdb25/A02-0220%20E%20LR.pdf [3] h t t p : / / b u s i n e s s t i m e s . c o m . v n / blackout-to-hit-firms-hard/ [15] https://library.e.abb.com/public/8d94471590c 7d439c1257d550 04c6061/T_D%20Newark. [4] http://www.bloomberg.com/news/2013-12-05/ pdf?filename=T_D%20Newark.pdf vietnam-faces-growing-threat-of-power-blackouts- southeast-asia.html [16] h t t p s : / / l i b r a r y . e . a b b . c o m / p u b l i c / a6029b4ecc85761ec12576740037818e/A02- [5] http://www.feemproject.net/cases/documents/ 0205%20E.pdf?filename=A02-0205%20E.pdf deliverables/D_05_1%20energy%20supply%20 externalities%20update_Dec_07.pdf [17] Decision No. 1208/QD-TTg approving the seventh power development plan for the period 2011 to [6] The National Association of Regulatory Utility 2020 with a vision towards 2030. Commissioners, “Evaluating Smart Grid Reliability Benefits For Illinois” , 2011. [18] http://www.nldc.evn.vn/Upload/NewsGroup/ Files/02122011091633.pdf [7] ERAV, , “The way forward for Smart Grid in Vietnam” November 2013. (https://www.giz.de/fachexpertise/ [19] Ngo Son Hai, Nguyen The Huu, “Operational downloads/2013-en-pep-fachveranstaltung-smart- Problems and Challenges in Power System of grids-nguyen-vu-quang.pdf) Vietnam”, National Load Dispatch Centre of Vietnam. [8] KEMA consulting, “Successful integration and automation relies on strategic plan“ , Electric Energy , presentation from [20] EVN, “EVN Smart Grid Plan” (http://www.electricenergyonline.com/show_ November 2013. article.php?mag=3&article=76) [21] http://www.qualitrolcorp.com/mwginternal/ [9] U.S. Department of Energy, Deployment of de5fs23hu73ds/progress?id=gJgkdyBClV synchrophasor systems: Decision and cost impact, [22] https://www.hsb.com/TheLocomotive/AnAnalysis September 2014 ofInternationalTransformerFailuresPart1.aspx [10] Goh, H.H., Q.S. Chua, S.W. Lee, B.C. Kok, K.C. [23] http://www.qualitrolcorp.com/mwg-internal/ Goh and K.T.K. Teo, “Operational Problems and de5fs23hu73ds/progress?id=+n5jlBo/W6 Challenges in Power System of Vietnam” , American Journal of Applied Sciences 11 (5): 717-731, 2014 [24] http://vietnamnews.vn/print/200163/ha-noi-suffers- widespread-blackout.htm [11] G. Giannuzzi, C. Sabelli, R. Salvati, R. Zaottini, C. Candia, M. Cignatta, A. Danelli, M. Pozzi, “Voltage [25] h tt p : / / b u s i n e s s t i m e s . c o m . v n / b l a cko u t - t o - and Angle Stability Monitoring: Possible Approaches hit-firms-hard/ in the Framework of a Wide Area Measurement [26] S. M. Amin and A. M. Giacomoni, “Smart Grid- Safe, System (WAMS)” , C2-114, CIGRE 2008 Secure, Self-Healing: Challenges and Opportunities [12] Ngo Son Hai, Nguyen The Huu, “Operational , in Power System Security, Resiliency, and Privacy” Problems and Challenges in Power System of IEEE Power & Energy Magazine, pp. 33-40, Vietnam” , National Load Dispatch Centre of Vietnam January/February 2012. 218 Volume 2: Cost-Benefit Analysis 219 [27] U.S. electricity blackouts skyrocketing – CNN. http:// [31] A. L’Abbate, G. Migliavacca , U. Häger, C. Rehtanz, edition.cnn.com/2010/TECH/innovation/08/09/ S. Rüberg, H. Ferreira, G. Fulli and A. Purvins, smart.grid/ “The role of facts and HVDC in the future pan- European transmission system development” , , Scientific [28] Amin and Schewe, “Preventing Blackouts” ERSE, Technische Universität Dortmund and American, pp. 60-67, www.Sciam.com, May 2007 Joint  Research  Centre. http://iet.jrc.ec.europa. [29] The Guidebook for Cost/Benefit Analysis of Smart eu/ses/sites/iet.jrc.ec.europa.eu.ses/files/ Grid Demonstration Projects, EPRI, Page 65. publications/reqno_jrc58566_acdc2010_paper.pdf [30] Nguyen Viet Cuong (EVN), “Power System , Philippines, 2007 Recovery in Vietnam” MAPS, FIGURES, AND TABLES SOURCES ENDNOTES (1) V. Giordano, I. Onyeji, G.Fulli, M. S. Jiménez, C. 1. According to the e-mail from NPT received on May 5th, Filiou, ”Giudelines for conducting a cost-benefit 2015 and meeting with NLDC held on April 21st, 2015. analysis of Smart Grid projects”, JRC, REFERENCE 2. Smart Metering and Smart Grid Strategy for the King- REPORTS, 2012. dom of Saudi Arabia. (2) International Energy Agency, South East Asia 3. The loss factor is the ratio of average power loss for a Energy Outlook, 2013. year to the loss at rated power during the same period. (3) Security of the European Electricity Systems, 4. The amount of equivalent hours is the number of hours Conceptualizing the Assessment Criteria and Core per year which the rated power would have to continue Indicators, University of Cambridge, Electricity to give the same total energy loss as that given by the Policy Research Group, November 2012. variable load throughout the year. (4) U.S. Department of Energy, “Dynamic Line Rating 5. Each Vietnamese costumer suffers an average of inter- , 2014. Systems for Transmission Lines” ruptions of 4,461 minute per years according EVN in his (5) Energy Information Administration, “Levelized Cost presentation “EVN Smart Grid Plan” from November and Levelized Avoided Cost of New Generation 2013 [20]. Resources in the Annual Energy Outlook 2014” , 6. The SAS cost just includes automation not the substa- 2014 http://www.eia.gov/forecasts/aeo/electricity_ tion itself. generation.cfm 3 Volume 3: Regulatory and Performance Monitoring 221 Table of Contents A. Acronym List.......................................................................................................................225 B. Summary of Regulatory and Performance Monitoring...................................................227 C. Introduction.........................................................................................................................233 C.1 General Overview.........................................................................................................................................233 C.2 Document Structure.....................................................................................................................................233 D. Definition of the Refined Smart Grid Roadmap...............................................................235 D.1 Summary of Key Points...............................................................................................................................235 D.2 Time positioning of transmission system enhancement interventions..................................................235 D.3 Smart Grid initiatives time positioning......................................................................................................237 E. Performance Monitoring of the Smart Grid Program......................................................245 E.1 Key Points Summary....................................................................................................................................245 E.2 The Transmission Regulation in Vietnam...................................................................................................245 E.3 Design of the Key Performance Indicators for the Refined Roadmap ....................................................247 E.4 Technical Key Performance Indicators........................................................................................................248 E.5 Economic Key Performance Indicators......................................................................................................250 E.6 Regulatory Key Performance Indicators.....................................................................................................251 F. Revision of the Legal and Regulatory Framework...........................................................253 F.1 Key Points Summary....................................................................................................................................253 F.2 The Legal Framework...................................................................................................................................253 F.3 The Electricity Law.......................................................................................................................................254 F.3.1 Decree No. 137/2013/ND-CP...............................................................................................................255 F.4 Regulatory Framework................................................................................................................................256 F.4.1 Grid Code.............................................................................................................................................256 F.4.2 Smart Grid Roadmap ..........................................................................................................................258 F.4.3 Decision on Renewables.....................................................................................................................258 F.4.4 An overview of the Power Master Plan VII....................................................................................................259 F.4.5 Electricity Market Roadmap.................................................................................................................260 F.4.6 Organizational Structure of Regulator..................................................................................................261 F.5 Topics that Impact the Regulation of Smart Grids.....................................................................................262 F.5.1 System Security Policy........................................................................................................................262 F.5.2 Renewable Energy Policy.....................................................................................................................263 F.5.3 International Interconnection policy.....................................................................................................263 F.5.4 Quality of Service Policy......................................................................................................................264 F.5.5 Smart Grid Policy.................................................................................................................................264 F.5.6 General policy for investment incentive in transmission and recovery mechanism.................................265 F.6 Recommendations for Implementation.....................................................................................................265 F.6.1 Roles and Responsibilities...................................................................................................................267 F.7 Conclusions and next steps.........................................................................................................................268 Annex 1. Proposed Amendment to the Decision No.: 1670QĐ-TTg.....................................271 References.................................................................................................................................275 Maps, Figures and Tables Sources.................................................................................................................275 Endnotes........................................................................................................................................................275 223 A. Acronym List AMI Advanced Metering Infrastructure NLDC National Load Dispatch Centre CAPEX Capital Expenditure NPT National Power Transmission Corporation CBA Cost Benefit Analysis OPEX Operational Expenditure COS Cost-of-service regulation PMU Phase Measurement Unit DGA Dissolved Gas-in-oil Analysis PQ Power Quality DGE Directorate General of Energy RACI Matrix that map the roles and responsibili- ties (Responsible, Accountable, Consulted DLR Dynamic Line Rating and Informed) DMS Distribution Management System ROR Rate-of-return regulation EIRR Economic Internal Rate of Return SAIDI System Average Interruption Duration EMS Energy Management System Index ENS Energy Not Served SAIFI System Average Interruption Frequency Index EPRI Electric Power Research Institute SAS Substation Automation System ERAV Electricity Regulatory Authority of Vietnam SCADA Supervisory Control And Data Acquisition EVN Electricity of Viet Nam SO System Operator FLS Fault Locator System SVC Static Var Compensator GIS Geographic Information System TLC Telecommunication HVDC High Voltage Direct Current TLSA Transmission Line Surge Arrester IE Institute of Energy TO Transmission Owner IRENA International Renewable Energy Agency TNO Transmission Network Operator JRC Joint Research Center TSO Transmission System Operator KPI Key Performance Indicator VCGM Vietnam Competitive Generation Market LLS Line Locator System VCRM Vietnam Competitive Retail Market LSA Line Surge Arrester VCWM Vietnam Competitive Wholesale Market MOIP Ministry of Industry and Trade VoLL Value of Lost Load MP VII Power Master Plan VII WAMS Wide Area Monitoring System NASPI North American SynchroPhasor Initiative NERC North American Electric Reliability Corporation 225 B. Summary of Regulatory and Performance Monitoring This document presents the Regulatory Performance c. Wide Area Monitoring System; Monitoring of the Smart Grid Program, and a strategy for d. Lightning Location System; its implementation. e. Geographic Information Systems; Originally, the Smart Grid initiatives were tailored to fit f. Substation Automation System; the specific needs of Vietnam, taking account of not only the best international practices and experiences, but also g. Static Var Compensator; the current Vietnamese operational problems and the h. Fault Locator System; and status of their Smart Grid projects. During this analysis, some key areas or “pillars” were identified for implemen- i. On-line-Dissolved Gas-in-oil Analysis. tation in order to increase the level of security and reli- ability of the Vietnamese power system. The following is achievable in the medium-term: The initial task performed was the prioritization of all a. High Voltage Direct Current technology. the Smart Grid initiatives relevant to the Vietnam power sector according to a set of technical criteria that were For the long-term no new initiatives have been planned, identified as part of the Technical Analysis. The technical but the completion of ones already undertaken in short/ analysis identified the Smart Grid initiatives appropri- medium-term is expected. ate for Vietnam as discussed in ‘Report  1    Chapter  F’. These solutions were initially positioned on a technology- In addition a regulatory analysis and a market analysis focused timeline. were conducted with the aim of understanding the possi- ble impact upon re-positioning the Smart Grid initiatives. The second task conducted was a Cost-Benefit analysis The market roadmap and the milestones established in aimed at identifying the costs and benefits of each pro- Decision No.  63/2013/QDTTg, dated 8 November 2013 posed Smart Grid initiative. This process also evaluated provided a complete overview of the initiatives and the their economic parameters in order to understand the market development in Vietnam. This suggests that real added value of each initiative. This analysis helped these roadmaps (market and Refined Smart Grid) are to identify the most suitable solutions and repositioned consistent at a high level and confirmed the most recent them in the timeline according to these results. positioning of the Smart Grid initiatives in the timeline. Three different time horizons were considered for the Figure 104 below shows a complete roadmap and its rela- development of the various applications: tionship to the market with milestones for those Smart Grid initiatives approved by Decision No. 1670QĐ-TTg a. Short term (within next 5 years); (shown in green). The figure shows the refined Roadmap and the recommended “pillars” (in light blue). b. Medium term (within next 10 years); and c. Long term (within next 15 years). In order to achieve effective Performance Monitoring of the Smart Grid Program and the impact of the Smart Grid In the light of this prioritization and taking account of the initiatives on the power system, three different types of results from the economic analysis the applications were Key Performance Indicators (KPIs) at three different lev- ordered according to their benefit-cost ratio. Those that els (shown in Figure 3) were identified in order to mea- should start in the short term are given below: sure and monitor the Refined Roadmap. a. Dynamic Thermal Circuit Rating; The KPIs are based on the current regulatory approach for transmission activity in Vietnam and the price control b. Power Quality Monitoring System and Metering mechanism detailed in Circular No. 14/2010 / TT-BCT from Data Acquisition System; 15th of May 2010. In line with the current regulation, the 227 228 FIGURE 104: COMPLETE TIME POSITIONING OF SMART GRID INITIATIVES CONSIDERING THE APPROVED ROADMAP FOR SMART GRIDS AND THE MARKET Smart Grid to Enhance Power Transmission in Vietnam Source: Authors Volume 3: Regulatory and Performance Monitoring 229 The KPIs address three different areas as follows: FIGURE 105: SMART GRID ROADMAP ASPECTS a. Technical: The performance indicators for the evaluation of a successful technical implementa- tion of each Smart Grid initiative; b. Economic: The benefit/cost ratio values calcu- lated in the Cost-Benefit Analysis; and c. Regulatory: These indicators measure the effect on the projected benefits of delays or modifications in the installation steps of each Smart Grid initiative. The KPIs monitor progress within the three aspects at three different levels. The base level or Project level is com- prised of mostly technical and economic indicators. The mid-level, or Smart Grid program level focuses on the imple- mentation progress of the program as a whole while the top level or system level measures the impact of the Smart Grid implementation on the Vietnamese power system1. Source: Authors The KPIs also pinpoint the enabling role of the Regulatory Authority which is tasked with achieving general policy targets, i.e. sustainability, reliable transmission network, KPIs will set a target to be achieved and there will be and security of supply. Table 75 presents the impact of penalties if the final target set by the regulator (based on each KPI on the major objectives for the Vietnamese the recommended values for the KPIs) is not achieved. power system. TABLE 75: MAP OF KPIS WITH MAJOR OBJECTIVES Major Objectives Enhanced Reliability of transmission Security Smart Grid Initiative KPI describing the expected improvement network of Supply Sustainability Reduction of time to attend fault site by maintenance crew and Fault Locator System X X X elapsed time to repair Voltage collapse prevention X Wide Area Monitoring System Out-of-steps prevention X Energy Not Served (ENS) reduction per year for each substation Substation Automation System X X X equipped with SAS Lightning Location System Percentage reduction of transient faults affecting the lines X X Mean square error between the value acquired by the meters and Metering Data Acquisition System X the value calculated by the settlement for the same meters 95% variation interval of voltage level of network “pilot nodes” X X X Static Var Compensator Voltage collapse prevention X X X Geographic Information Systems Reduction of management costs X Power quality monitoring system Percentage reduction of voltage dips X The reduction of power losses X High Voltage Direct Current technology High power factor X On-line Dissolved Gas-in-oil Analysis Fault number reduction X X Dynamic Thermal Circuit Rating “Ampacity” increase X X X Source: Authors 230 Smart Grid to Enhance Power Transmission in Vietnam The values of the proposed technical and economic KPIs c. International Interconnection policy; are shown in Table 76. d. Quality of Service regulatory policy (indicators, incentives, penalties); The proposed regulatory KPIs aim to monitor and control the pace of evolution and implementation of each initia- e. Smart Grid Policy; and tive within the overall Smart Grid Program. These are f. General policy for investment incentive in trans- generic for the initiatives and measure the percentage of mission and recovery mechanism. implementation according to the agreed target. The main recommendations are summarized below: This document also performs a review and analysis of the Legal and Regulatory framework, highlighting the a. The system security policy is an implicit part of changes that have occurred over the last ten years in the Grid Code and needs to be complemented Vietnam’s electricity market. The purpose of this analy- with the on-line security assessment criteria in sis was to determine the policies currently in place that order to avoid repeating past errors. impact the Smart Grid initiative. b. The Grid Code should also establish under the The following policies were analyzed: same policy, the tools that the System Operator must have in order to evaluate the security and a. System Security policy; perform on-line monitoring and on-line control of the voltage/dynamic stability of the Vietnamese b. Renewables and their policies and incentives; Power System. TABLE 76: TECHNICAL KPIS PROPOSED FOR EACH SMART GRID INITIATIVE Technical KPI Satisfactory Smart Grid Initiative Performance indicator threshold Economic KPI Reduction of time to attend fault site by Fault Locator System 25% B/C ratio: 1.17 maintenance crew and elapsed time to repair Voltage collapse prevention 15%-35% Wide Area Monitoring System B/C ratio: 17.82 Out-of-steps prevention 15%-35% Energy Not Served (ENS) reduction per year for Substation Automation System 100MWh B/C ratio: 2.13 each substation equipped with SAS Percentage reduction of transient faults affecting Lightning Location System 20%-30% B/C ratio: 6.89 the lines Mean square error between the value acquired Metering Data Acquisition System by the meters and the value calculated by the 0.4%-0.8% B/C ratio: 39.26 settlement for the same meters 95% variation interval of voltage level of network +/-5% of the Static Var Compensator “pilot nodes” rated voltage B/C ratio: 1.21 Voltage collapse prevention 15%-35% Geographic Information Systems Reduction of management costs 10%-15% B/C ratio: 3.61 Power quality monitoring system Percentage reduction of voltage dips 20% B/C ratio: 39.26 High Voltage Direct Current technology Power factor 0.7 B/C ratio: 1.56 On-line Dissolved Gas-in-oil Analysis Fault number reduction 80% B/C ratio: 1.13 Dynamic Thermal Circuit Rating “Ampacity” increase 5%-25% B/C ratio: 35.11 Source: Authors Volume 3: Regulatory and Performance Monitoring 231 c. The renewables policy is generally focused on f. It is recommended that the Smart Grid policy com- wind and biomass sources. But, the criteria, plement Decision No.: 1670QĐ-TTg of November methodologies and incentives established are 2012 with both KPIs and penalties, in order to focused on the planning procedures rather than measure and track the performance of Smart Grid on fostering and assessing renewable energy initiatives. As mentioned before, the final values developments. It is recommended that the renew- of KPIs and penalties should be defined by ERAV ables policy complement the developed Smart based on the proposed values in this report mind- Grid roadmap in order to take advantage of those ful of the overall regulatory framework. applications that ease the integration of renewable g. Finally, Circular No. 14/2010 / TT-BCT from 15th sources in to the transmission network. of May 2010 describes a detailed mechanism d. The international interconnection policy needs for the recovery of investments in the transmis- a greater degree of clarity. This may have some sion system. The Circular clearly establishes that significance for the development and deployment each year, based on the principle of ensuring full of some of the Smart Grid initiatives, e.g., HVDC cost recovery and retaining permitted profits the interconnection, more stringent requirements for operator is required to run the transmission grid online monitoring and security assessment to according to the quality regulations and to meet ensure frequency/voltage problems do not cas- key financial targets for the investment and devel- cade from one system to another, etc. A policy opment of the transmission grid. At present no that addresses these points may enable the inclu- improvements are recommended for the present sion of technologies like HVDC and to increment mechanism. the use of SVC for maintaining the stability of the In conclusion some recommendations for the implemen- systems and links. tation of the Smart Grid are presented. These emphasize e. The Electricity Law does not define penalties or the roles played by the different participants involved incentives for failing or exceeding the quality of (ERAV, NPT, and NLDC). The following matrix presents service requirements. The revision of the Grid the activities to be performed until the completion of the Code is also silent on the issue of penalties for program. The responsibility assignment matrix known as failing to meet minimum standards in the qual- the RACI matrix describes the participation by various ity of service. The lack of penalties weakens the roles in completing tasks or deliverables for the imple- introduction of Smart Grid technologies, which mentation of the Smart Grid program. are being pushed by the industrial user commu- nity who have a poor perception of the quality of The main activities in order to implement the refined service of electricity supplies. roadmap are those described in the Table 77. TABLE 77: RACI MATRIX FOR THE ROLES AND RESPONSIBILITIES OF THE REFINED ROADMAP Activity NPT NLDC ERAV IE Internally approve the Refined Roadmap R R Present the Final Report to other institutions R I I I Define the priorities for Implementation in the short-term R R A Request approval of the Refined Roadmap to regulator R R A Approve the Refined Roadmap and the Smart Grid C C R I initiatives in the short, medium and long term Based on the recommended KPIs, define the final C C R targets for the KPI for the implementation Include the approved investments in the Master Plan CA CI I R Follow up the approved Smart Grid investments through the KPIs CI CI R Source: Authors R = Responsible; A= Accountable; C=Consulted; I= Informed. 232 Smart Grid to Enhance Power Transmission in Vietnam Complementing the implementation activities of the A Decision for the approval of the KPIs to control and Refined Roadmap, those agencies responsible for per- monitor the Smart Grid initiatives is also required. it is forming detailed studies and implementation of each recommended that the approval of the KPIs is performed Smart Grid initiative are also presented in Table 78. separately from the Decision of the Refined Roadmap in order to have enough flexibility to allow ERAV to change A proposed Amendment to the current Smart Grid Deci- these values (if required), without having to issue a new sion was documented in the Annex “Proposed Amend- Decision for the Roadmap because a change of the KPI ment to Decision No.: 1670QĐ-TTg. ” limits. TABLE 78: RESPONSIBLE FOR DETAILED STUDIES AND IMPLEMENTATION OF THE SMART GRID INITIATIVES Responsible for Responsible for Smart Grid Initiative Detailed Study Implementation Power quality monitoring and Metering Data Acquisition Systems NLDC NPT Dynamic Thermal Circuit Rating NPT NPT Wide Area Monitoring System NLDC NPT Lightning Location System NPT NPT Geographic Information Systems NPT NPT Substation Automation System NPT NPT High Voltage Direct Current technology NPT NPT Static Var Compensator NLDC NPT Fault Locator System NPT NPT On-line Dissolved Gas-in-oil Analysis NPT NPT Source: Authors C. Introduction C.1 General Overview for conducting a cost-benefit analysis of Smart Grid proj- ects” recommended by the Joint Research Centre Insti- This document presents the Regulatory Performance tute for Energy and Transport (JRC). Monitoring of the Smart Grid Program and a strategy for its implementation. Finally, the aim of this document is to present the final phase of the Roadmap for a Smart Grid in the light of The Project started by designing the strategy and gath- the Technical and Economic analyses, the performance ering information in order to refine the Roadmap of the monitoring of the Smart Grid Program and the revision of Smart Grid program for Vietnam. The execution of the the legal and regulatory framework. project followed the sequence presented in Figure 106, which started by identifying the possible Smart Grid The recommendations for implementation are also pre- Applications and Smart Grid Equipment that may help to sented in this document. resolve the identified problems. The methodology for developing a Smart Grid roadmap C.2 Document Structure initially defined a number of essential concepts (e.g. state estimation, security assessment, remote control and regu- This report is structured as follows: lation, asset monitoring and management) as the necessary “pillars” that are vital for the creation of a smart network. a. The first part is composed of chapter ‘C’ and pres- ents the final refined roadmap that takes account The Task-1 report defined a common shared vision of of both the technical and economic prioritization components and equipment for the development of the based on the cost-benefit analysis. The initiatives Smart Grid in Vietnam starting with the current operating have been positioned on a timeline and propose model and the predicted status of the electricity sector. the best starting point for the solutions as well as suggested elapsed times for their development. The Smart Grid initiatives were tailored to fit the specific needs of Vietnam, tak- ing account of not only the best inter- FIGURE 106: GENERAL OVERVIEW OF THE PROJECT national practices and experiences, but also the current Vietnamese operational problems and the status of their Smart Grids projects. This technical analysis identified the Smart Grid initiatives that are viable in Vietnam. Following a technology- focused investigation these Smart Grid solutions were prioritized2. The Cost-Benefit analysis aimed at identifying the costs and benefits of each proposed Smart Grid initiative and evaluating their economic parameters in order to understand the real added value of each initiative3. The Cost-Benefit Analysis (CBA) fol- Source: Authors lowed the key steps of the “Guidelines 233 234 Smart Grid to Enhance Power Transmission in Vietnam b. The second part is composed of chapter ‘D’’ and expedite the approval and implementation of the addresses the performance monitoring of the Refined Smart Grid roadmap. Smart Grid Program and presents the key perfor- Finally, a summary of the key points and the recom- mance indicators in order to monitor and control mended regulatory improvements is presented. the implementation of the program. c. The third part is composed of chapter ‘E’, which A dedicated Annex reports on the “Proposed Amend- performs a review of the regulatory framework . ment to Decision No.: 1670QĐ-TTg” and points out possible improvements in order to D. Definition of the Refined Smart Grid Roadmap D.1 Summary of Key Points b. Power Quality Monitoring System and Metering Data Acquisition System; This chapter presents the final prioritization of all the c. Wide Area Monitoring System; Smart Grid initiatives relevant to the Vietnam power sec- tor, positions them on a timeline and proposes the best d. Lightning Location System; starting point for the solutions as well as suggesting e. Geographic Information Systems; elapsed times for their development. f. Substation Automation System; The prioritization presented below is a refinement of the g. Static Var Compensator; Vietnamese Smart Grid roadmap and defines a phased implementation plan. This analysis has taken account of h. Fault Locator System; and each Smart Grid initiative, namely: i. On-line-Dissolved Gas-in-oil Analysis. a. Task 1 report: The technical reasons described in The following is achievable in the medium-term: the technical analysis report; and b. Task 2 report: The economic results of the Cost- a. High Voltage Direct Current technology. Benefit Analysis and the risk assessment. For the long-term no new initiatives have been planned, As in the technical analysis report three different time hori- but the completion of ones already undertaken in short/ zons were defined for the development of the initiatives: medium-term is expected. a. Short term (within next 5 years); D.2 Time positioning of transmission b. Medium term (within next 10 years); and system enhancement c. Long term (within next 15 years). interventions In the light of a prioritization based on their cost benefit As stated in the Task-1 Report, pillars were introduced ratio, the following initiatives should start in the short because the majority of the Smart Grid initiatives require term: parallel developments of multiple systems to support and/or integrate with new technologies. A case in point a. Dynamic Thermal Circuit Rating; FIGURE 107: TECHNOLOGICAL GAP THAT VIETNAMESE TRANSMISSION SYSTEM HAS TO FILL Source: Authors 235 236 FIGURE 108: TRANSMISSION SYSTEM ENHANCEMENT INTERVENTIONS TIME POSITIONING Smart Grid to Enhance Power Transmission in Vietnam Source: Authors Volume 3: Regulatory and Performance Monitoring 237 is the Telecommunication (TLC) system, which is pivotal d. The Fault Locator System with recommended to the full development of SAS or WAMS. preliminary activities are positioned in the short term as is their finalization; To reach an adequate technological level in the Vietnam- e. The Static Var Compensator with some prelimi- ese transmission system for enabling the development nary activities are positioned in the short term of the Smart Grid a “transmission system enhance- whilst finalizing the expected installed capacity ment” was deemed to be necessary. The gap analysis, will impinge on the medium term; performed in the Task-1 Report identified the following basic building blocks (or ”pillars”) as being fundamental f. Whilst the Wide Area Monitoring System starts to the success of the initiatives: in the short term, its complete rollout will be con- cluded in the medium term. The prioritization of a. Planning and AMS basic strategies improvements; the main data communication lines and area links are in the short term; b. State Estimation and N-1 Security Assessment; g. The Substation Automation System, including c. Load-Frequency Regulation strategies improvements; building/upgrading remote control centers, has d. Protections System improvements; and already commenced and is positioned in the short term but will not be concluded until the medium e. General TLC system improvements. term; The details and the concepts shown in Figure 107 were h. The Power Quality Monitoring system and Meter- detailed in the Task-1 Report along with a brief time- ing Data Acquisition System start in the short line for the implementation of the basic interventions term but will not be concluded until the medium thus completing the necessary “transmission system term; enhancement” prior to the full deployment of the Smart i. The High Voltage Direct Current technology with Grid technologies. the required preliminary studies and activities in the short term but will not be concluded until the Figure 108 shows the various interventions required to medium term; and establish the ”pillars” depicted on a realistic timeline. j. The On-line-Dissolved Gas-in-oil Analysis has This timeline positioning is based on the information col- already started and is positioned in the short lected during the discovery process in Vietnam. These term but it will last for the whole considered time interventions do not require any prerequisite activity and horizon. can start immediately. The time durations shown for the implementation process of the different interventions is The roadmap for the development of the Smart Grid initia- a conservative estimate based on similar activities per- tive in the context of the emerging Vietnamese electric- formed in other countries (e.g. Italy). It is possible that ity market is presented below in Figure 109. The overall the actual elapsed times will be less because some paral- aim is to consolidate and strengthen the operation of the lel initiatives have already been planned or are currently wholesale market before introducing a retail market. in progress. The operation of the wholesale electricity market that is planned to commence in 2016 requires that those tech- D.3 Smart Grid initiatives time nologies and initiatives that will most enable the imple- positioning mentation of the Smart Grid are initiated and in place before the year 2022. The Smart Grid technologies will The following provides a brief overview of the technical help to stabilize the power supply and enhance the reli- and economic prioritization of some key projects: ability of the transmission network. These technologies will help to increase power transfer bandwidth between a. The Geographic Information Systems is posi- north and south, which will establish a secure and reliable tioned in the short term; power supply. A stable power supply also means stable prices and provides opportunities that will attract invest- b. The Dynamic Thermal Circuit Rating is positioned ments and increase competition in the marketplace. in the short term; c. The Lightning Location System is positioned in In general, the benefits for the market can be summa- the short term; rized as follows: 238 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 109: POWER MARKET DEVELOPMENT ROADMAP, PERFORMED AND PRESENTED BY ERAV Source: ERAV, 2010, (1) a. The ability to connect and operate of generators is likely to offer the largest possible number of of all sizes and technologies; applications that would benefit the enterprise. Given that the total cost (CAPEX: $175,000 and b. Allow consumers and investors to play a part in OPEX: $262,500) is much lower than for most optimizing the operation of the system; of the other systems and the economic indica- c. Enable the integration of renewable sources help tors are positive (EIRR: 48% and B/C ratio: 3.61) reduce the carbon footprint of the whole electric- it makes sound economic and technical sense to ity supply system, implement this system in the short term. Further, no particular risks have been highlighted. The d. Sustain and even improve the existing levels of implementation activity basically comprises: system reliability, quality and security of supply; i. Careful selection of all the applications that e. Sustain and improve the existing services effi- would benefit from this initiative; ciently; and ii. Development of procedures and strategies to f. Foster market integration with neighboring coun- store and share GIS data; and tries to facilitate the creation of a regional inte- grated market. iii. Implementation of software tools for process- ing and displaying data. The positioning of all the Smart Grid initiatives has been b. Dynamic Thermal Circuit Rating. This initiative confirmed based on the technical and economic analyses has been positioned in the short term. The tech- as well as the current status of the Vietnamese market. nical analysis had originally positioned this initia- These initiatives need to be in place to ensure the power tive in the long term on the basis that it would be market is based on a strong, reliable and self-healing better to wait for the current rapid growth rate of transmission network. Note that the transmission sys- the transmission network to slow down in order tem is the physical nexus where production and demand to leverage this application on a large scale. How- meet and it is imperative that it is consistently reliable in ever, since the CBA has revealed that its eco- order to facilitate its development. nomic indicators are extremely positive (EIRR: “All positive cash flows” and the B/C ratio: 35.11), Thus, based on the technical, cost-benefit analysis as it makes both technical and financial sense to well as the power market roadmap the final positioning implement this technology in the short term. of the Smart Grid applications that have been positioned Developing a rigorous system operation strategy over the short-medium and long term are as follows: that fully exploits the dynamic rating application will easily mitigate the related risks. The imple- a. Geographic Information Systems. It is posi- mentation activity basically comprises: tioned in the short term. As stated in the tech- nical analysis, the prior development of other i. Careful selection of the lines to be monitored; systems like SAS or WAMS will be important to ii. Choice of the monitoring devices; enable the implementation of this solution which Volume 3: Regulatory and Performance Monitoring 239 iii. Development of algorithms and procedures The assignment of dedicated and properly viii. for real-time temperature estimation; and trained staff. iv. Integration of the information and results d. Fault Locator System. This initiative is posi- obtained from Dynamic Thermal Circuit Rating tioned in the short-term. The economic indicators and daily system operations. are lower than for other applications (EIRR: 13% and B/C ratio: 1.17) and the investment is quite c. Lightning Location System. This initiative has high (CAPEX: $8,400,000). Also the risk assess- been positioned in the short term. The technical ment has highlighted that the “Investment uncer- analysis had considered this as a short-term solu- tainty” is most critical for this initiative. On the tion due to the criticality of the lightning problem other hand, the NPT FLS project is already under- in Vietnam. The intelligence of the system is sup- way and is quite independent of all the other plied by the location system and not the arresters initiatives. Therefore, the recommendation is to (which are dumb devices). The economic indica- evaluate the real benefits of this technology on tors (EIRR: 164% and B/C ratio: 6.89) strongly a small number of lines and then decide if it is recommend investment in this solution. All the worth deploying across the estate. For this rea- risks associated with this initiative can be miti- son only a pilot program for FLS benefits evalu- gated by focusing the investments on develop- ation has been positioned in the short term. If in ing applications fed by LLS data and carrying the next few years the cost of this technology out commensurate training for the control room decreases its current positioning can be recon- operators to exploit LLS information. As stated in sidered and, if required, brought forward. Finally, the technical analysis report, the basic implemen- the implementation activity basically comprises: tation phases are: i. Careful selection of the lines to be monitored; i. The evaluation of all the available technologies with respect to the specific needs of all the ii. Installation and wiring of the devices; and transmission utility functions that could ben- iii. Development of algorithms and procedures efit from such a system; for FLS data exploitation. ii. The evaluation of the number of sensors e. Static Var Compensator. Some preliminary needed to cover the country with the capa- activities are required to be performed in the bility for homogeneous and high detection short term while the complete roll-out of estate- performance, event discrimination, location wide capability has been positioned in the begin- accuracy and 24/7 availability; ning of the medium term. Such preliminary iii. The evaluation of the orography and conse- activity is highlighted in the final time positioning quently the identification of the possible ideal of Smart Grid initiatives. Further, the risk analy- locations for the sensors (electromagnetic sis has revealed that Vietnam’s rapidly growing noise, structural shields, physical security, ter- power network would significantly complicate rain, telecommunication links, etc.); the choice of the locations of SVC devices. To mitigate such risks relocatable SVCs have been iv. Appropriate contractual agreements with local suggested, which will allow the flexibility of tem- site owners wherever necessary; porary installations while retaining the invest- v. The execution of all civil and electrical works at ment despite unpredictable topology changes the identified sites, including power and tele- due to future growth. Even though the total cost communication cabling if needed; is quite high (CAPEX: $31,500,000 and OPEX: $1,255,500) the economic indicators are good vi. The implementation of an Operational Centre (EIRR: 14% and B/C ratio: 1.21), which make provided with specific power and telecommu- this investment a sound economic choice. Fur- nication schematics as well as the main server thermore, the SVC initiative achieves significant for data analysis where all sensor data will be benefits both in terms of integration of renewable received, processed and stored; energy generation and in terms of blackout pre- vii. The fine tuning of LLS (using the most immedi- vention. Moreover, the criticality of the voltage ately available data), implementing site correc- stability issue in the Vietnamese [1] transmission tions of detection parameters and thresholds network argues against delaying this measure where needed; and for too long because it may jeopardize system 240 Smart Grid to Enhance Power Transmission in Vietnam security and availability. The plan to start its full are recommended for commencement in the implementation in the latter part of the short- short term but its complete rollout will not con- term is very likely the right choice, as it will allow clude until the medium term. Both these initia- a suitable time for the detailed feasibility study tives have been have been positioned in the phase. Therefore, the already planned devices short-term because their total cost (CAPEX: can be installed but the full deployment of the $301,500 and OPEX: $97 ,200) is amongst the application has to be positioned in the mid-term. lowest of all the initiatives while the economic indicators are compelling (EIRR: 797% and B/C f. Wide Area Monitoring System. It is recom- ratio: 39.26). In order to mitigate the assessed mended that this application begin in the short risks before beginning the deployment of these term with the complete rollout being concluded initiatives it is important to carefully consider all in the medium term. The prioritization of the the regulatory aspects. The implementation activ- main data communication lines and area links ity is basically comprised of: are positioned in the short term. As stated in the technical analysis report WAMS is a solution that i. Careful analysis of all the regulatory aspects; ”enables” some of the others (e.g. Dynamic Ther- ii. Development of a remote control center; mal Circuit Rating) and aims to solve a large num- ber of issues (e.g. voltage and transient stability, iii. Development of a strategy for the location of defense plan deficiencies, etc.). The sooner this devices; initiative commences the better. Furthermore, iv. Installation and cabling of devices; and WAMS’s economic indicators are strongly posi- tive (EIRR: 204% and B/C ratio: 17 .82) and there v. Implementation of software tools for process- are no unconquerable risks as long as the WAMS ing data. based applications are properly developed. The i. On-line Dissolved Gas-in-oil Analysis. CBA implementation activity is comprised of: results show that the investment is less attrac- i. Development of a remote control center; tive in economic terms than other initiative (EIRR: 12% and B/C ratio: 1.13) and the total cost ii. Development of a strategy for the location of is quite high (CAPEX: $77 ,592,000 and OPEX: PMUs; $3,343,245). But even if the high cost of moni- iii. Installation and cabling of PMUs; toring devices would make this solution a high- risk economic strategy, it is worth to consider iv. Implementation of WAMS based applications; the average lifetime of this type of transformers and (about 25 years) and to start investing in this tech- v. Integration of information and results obtained nology in the short term. The transformers’ fault from WAMS based applications and daily sys- risk in fact is not positioned in the near future tems operation. but it is widespread in all their lifetime, which is longer that the time horizon considered for the g. Substation Automation System. This is a NPT investment. As described in the technical analysis project that has already reached a significant level (see Report 1, paragraph ‘F .11’), it is fundamental of development. The initiative, which includes to start monitoring transformers as soon as pos- building/upgrading remote control centers, has sible in order to effectively use the stored data for already started and is positioned, by default, in an accurate diagnostic in the future (15-20 years) the short term but its complete rollout will not on aged transformers, and so fully exploit DGA conclude until the medium term. The economic technology. Therefore the benefits of this initia- indicators are positive and the assessed risks tive are achievable only if the device installation can be successfully mitigated with an efficient starts in the short term. substation commissioning policy and adequate control of the gap between the roadmap and j. High Voltage Direct Current technology. In real installation pace. The implementation activity order to assess the economic feasibility of the includes the installation and the commissioning HVDC technology, the incremental cost of a new of new substations equipped with SAS. 800 km DC is link compared with the cost of an AC 500 kV solution. It has been assumed that the h. Power quality monitoring system and Meter- original planning for this installation only consid- ing Data Acquisition System. These initiatives ered the technical benefits of the AC line rather Volume 3: Regulatory and Performance Monitoring 241 than of the line itself in relation to the wider net- system and the Metering Data Acquisition System, which work. This initiative requires preliminary studies are intertwined with the installations of new substations, and activities that should be conducted in the will also be completed within the same ten-year window. short term and the implementation, if consid- ered feasible following the findings of the study, Figure 110 represents the final time positioning of Smart should be positioned in the medium term. How- Grid initiatives and defines the phased implementation ever, at the outset it can be safely assumed that plan for the Refined Vietnamese roadmap. the economic indicators are good with regard to the technology application per se and not the line The broad brushstrokes for the prioritization of the Smart itself. Further, despite the fact that the total incre- Grid initiatives have been completed. The project map mental costs are very high (CAPEX: -$16,800,000 shown below depicts the approved market rollout in Viet- and OPEX: $118,098,000), the EIRR has “All posi- nam and is based on the ratification provided by “Deci- tive cash flows” the B/C ratio is 1.56. The eco- sion No. 1670QĐ-TTg” of November 2012 [2] approving nomic indicators currently ignore several other the development of both the Smart Grid and the “pillars” strategic and technical benefits that if included required to enhance the transmission system. would likely make a very strong case for the development of HVDC technology in Vietnam. The complete map presented below in Figure 111 shows On balance it is worth planning the development the final timeline positioning of the Smart Grid initiatives of this technology because it could prove useful and defines the implementation of the refined roadmap. for both interconnections with neighboring coun- “Decision No. 1670QĐ-TTg” solutions are shown in tries [1] and for long links (e.g. 500kV link with green, the Smart Grid initiatives in blue and the “pillars” a length greater than 700km) connecting the in light blue. Northern and Southern parts of Vietnam. Further- more, HVDC technology is perhaps the most “Decision No. 1670QĐ-TTg” defines three different hori- ideally suited Smart Grid initiative for integrat- zons for the development of the Smart Grid: ing new variable renewable generation. In fact the increased transfer capacity and active power a. Phase 1/initial phase (2012-2016); control are fundamental benefits which would b. Phase 2 (2017-2022); and enable the installation of wind or solar power plants carrying the generated energy to the load c. Phase 3 (after 2022). areas and balancing the natural fluctuation of renewables. The actual implementation of HVDC This document refers to different initiatives for the Viet- is reliable only in the medium term since this namese electrical system developments taking into initiative requires quite a long preliminary activ- account both transmission and distribution networks. ity (about 4 years), necessary for the feasibility The distribution networks are outside of the scope study. Such preliminary activity is highlighted in of this project and have not been shown in Figure 111. the final timeline positioning of the Smart Grid While the applications for the distribution network are initiatives. After this study phase the real imple- well detailed, only generic interventions and improve- mentation activity (comprised of the construction ments for the transmission network have been shown; of the HDVC line/s) can start and may take, based for example, the “Development and implementation of on the consultant’s experience, about 4 years to advanced operation tools for the integration of large num- complete. ber of renewables” , listed in “Decision No. 1670QĐ-TTg” , is a clear objective but not a specific application. The creation of a timeline for the prioritization of the Smart Grid initiatives assumes a specific starting point Conversely, both the “pillars and the Smart Grid initia- at which the clock starts. Some of the initiatives have a tives, described previously in this chapter, address spe- development and installation cycle as long as five years cific applications for the transmission system. These, prior to becoming operational and economically beneficial therefore, are consistent with the requirements stated to the organization. The development process for SAS is in “Decision No. 1670QĐ-TTg” for the transmission already underway which is why it is has been positioned system. For example, some Smart Grid applications as a short term project i.e. within the next 5 years even like Static Var Compensators, High Voltage Direct Cur- though the installation will not actually be concluded until rent technology or Dynamic Thermal Circuit Rating can towards the end of the medium term. Equally the full be considered amongst the best Smart Grid initiatives implementation of WAMS, the Power quality monitoring 242 FIGURE 110: FINAL TIME POSITIONING OF SMART GRID INITIATIVES Smart Grid to Enhance Power Transmission in Vietnam Source: Authors FIGURE 111: COMPLETE TIME POSITIONING OF SMART GRID INITIATIVES CONSIDERING THE APPROVED ROADMAP FOR SMART GRIDS AND THE MARKET Volume 3: Regulatory and Performance Monitoring Source: Authors 243 244 Smart Grid to Enhance Power Transmission in Vietnam in terms of the integration with new variable renewable . tools for the integration of large amount of renewables” generation. In fact, increased transfer capacity is a funda- Further, initiatives like “Wide Area Monitoring System”, mental benefit, which will enable the installation of wind “Fault Location System” and “Lightning Location Sys- or solar power plants carrying the generated energy to tem and Surge Line Arresters installation” are viable the load areas. Such an objective is entirely consistent solutions to meet the requirements of the stated target with the target referred to by the requirement “Devel- “Fault recorder system, detection and protection system opment and implementation of advanced operation of outage wide-area” . E. Performance Monitoring of the Smart Grid Program E.1 Key Points Summary they are regulated. The peculiarities include very distinct timing issues, a monopoly over supply and vertical econ- This chapter contains the Key Performance Indicators omies with generation and load. required to measure and monitor the Refined Road- map. The key performance indicators will measure the Transmission is a monopolistic service. The economics progress towards a Smart Grid and assess the level of of transmission investment and the economies of scope smartness. and scale of service provision ensure that this will be the case for some time to come. Therefore, transmission The proposed indicators specify the enabling role of the service elements (e.g. prices) must be regulated. Regula- Regulatory Authority who is tasked with achieving gen- tion of the transmission provider is a substitute for com- eral policy targets, i.e. sustainability, reliable transmission petition, and therefore, its core objective is to prevent the network, competitiveness and security of supply. The transmission provider from charging customers a price framework introduces three types of KPIs, each with two above what would be the competitive price for access different levels having a specific program goal, individual and use [3]. In general, the regulator is also seeking to initiatives goal as well as a technical goal for the Refined effect efficient operations and investment decisions by Roadmap. The use of such KPIs will support the prepara- motivating the transmission provider to manage the sys- tion for the deployment of the Smart Grid applications. tem so it complements generation and distribution and enables competition in wholesale electricity trade in both KPIs for the Refined Vietnamese Roadmap have three the short and long term. main roles: The challenges for the regulation of transmission areas a. They measure the efficiency of the implementa- are threefold, regardless of the structure of ownership. tion processes, which are aimed at meeting the First, transmission is subject to network externalities goals of the NPT and are embedded within the associated with real time operations such as loop flow, Master Plan and regulatory targets; congestion and losses. This makes it difficult to assign responsibility for the marginal real-time system costs b. They form the basis of the monitoring process caused by transmission users. In turn, this makes defin- of the Smart Grid implementation activities, thus ing and assigning property rights difficult, especially if showing that each application is delivering vari- use of the grid is measured inaccurately or not at all as ous elements of new functionality needed in the it is today in some parts of the grid. Therefore, it makes transmission network in order to meet the over- relying on market-based investment and participant- arching goals of the program; and funded transmission expansion much more challenging. c. They support the Smart Grid regulatory process, which links the expected impacts of each Smart Second, investment in transmission networks exhibit Grid application to the deployment conditions. significant economies of scale and scope, lumpiness and externality effects. Scale effects in transmission The KPIs therefore aim to measure the contribution of the occur because the incremental cost of doubling the size Smart Grid applications in the context of the technical, of a new line may significantly lower the average cost economic and regulatory aspects. The results will help per MW compared to a line only half the size. In addi- ERAV and the various stakeholders to track the benefits tion, grid expansion comes in fixed sizes, which means and the expected results of the Smart Grid applications. that additions cannot be made in small increments of 1 MW to match the demand of individual customers. This means that many efficiently sized market-based trans- E.2 The Transmission Regulation in mission investment projects are too large and hence too risky for any single market participant. Furthermore, the Vietnam benefits (i.e., the positive externalities) associated with an increase in the transfer capability of the grid are nearly Electricity transmission services are characterized by a universally enjoyed. number of peculiarities that affect the manner in which 245 246 Smart Grid to Enhance Power Transmission in Vietnam Third, because of the strong network externalities asso- Sliding Scale (ROR bandwidth): In sliding scale or ROR ciated with investments that both widen and deepen bandwidth regulation, the utility’s allowed rate of return the transfer capability of the system (especially the high is benchmarked against a target or reference ROR that voltage system), expansion planning and investment pro- lies within a pre-specified dead-band. During the regula- cesses suffer from a ‘free-loader’ problem. tory lag, the actual ROR can vary within the dead-band without causing rate adjustments. If the actual ROR falls Further, considering these challenges and broader inter- outside the dead-band it can trigger profit sharing mecha- national experience in the regulation of the transmission nisms or rate reviews. activity, several approaches were considered and imple- mented in order to regulate transmission activity. The Yardstick Regulation: In yardstick regulation the perfor- interest in incentive regulation is not due to new con- mance of a regulated utility is compared against that of tributions from economic theory. Rather, the need for a group of comparable utilities. For example, the mean practical solutions has resulted in design and implemen- of the costs of a peer group of firms can serve as per- tation of regulatory arrangements that are not necessar- formance benchmark. The method was first proposed in ily in line with the theory [4]. The regulatory reforms have Shleifer 1985 and it is used to promote indirect competi- emerged as an alternative to the traditional rate-of-return tion between regulated utilities operating in geographi- (ROR) or cost-of-service (COS) regulation of utilities and cally separate markets. regulators have adopted a variety of approaches to incen- tive regulation. The main approaches to Incentive Regula- Partial Cost Adjustment: Another approach to incen- tion can be summarized as follows [5]. tive regulation is to link the price adjustments to changes in the utility’s own costs observed in a reference year. Rate of Return Regulation: The ROR regulation is the The cost minimization incentive is provided by periodic traditional approach to regulation of privately owned adjustments to prices that are less than proportional to monopolies and an alternative to public owned utilities. the actual changes in the costs. The method is a heavy-handed approach to regulation and it is generally identified with the regulation of inves- Menu of Contracts: The menu of contracts method is an tor-owned utilities. The ROR regulation allows the utility innovative approach to reduce the information asymme- to cover its operating and capital costs and earn a return try between the regulator and regulated firm. Under this on capital. scheme the regulator offers the utility a menu of incen- tive plans with a constant consumer welfare component. Price Cap Regulation: The price cap approach to utility The utility can choose between the incentives and the regulation is perhaps the most widely discussed and sig- flexibility in choosing among the alternatives reveals its nificant innovation in utility regulation and a viable alter- welfare-enhancing preferences. native to ROR regulation. The method was first proposed in Littlechild in 1983 and various versions of it have since The various incentive regulation methods presented been adopted in the regulation of infrastructure and util- above are usually not observed in a pure form. Rather, ity industries in the United Kingdom and other countries. practical considerations and multiplicity of the regulatory Price cap regulation essentially decouples the profits of objectives often result in using a combination of differ- the regulated utility from its costs by setting a price ceil- ent incentive regulation methods. For example, targeted ing. The method is also referred to as the ‘RPI-X’ model. incentive schemes can supplement the broad incentive For each rate period, normally between 3 to 5 years, the regulation methods. Also, incentive regulation may be price cap for each year is set based on the Retail Price combined with various profit or loss sharing schemes. Index and an efficiency factor X. Prices remain fixed However, hybrid schemes may result in inefficient for the rate period and the utility keeps or shares the resource allocation. achieved cost savings. Considering the Vietnamese context, the regulation of Revenue Cap Regulation: The revenue cap method the transmission activities, i.e. the price control mecha- regulates the maximum allowable revenue that a utility nism and methodology are established in Circular No. may earn. Similar to the price cap regulation, the aim of 14/2010 / TT-BCT from 15th of May 2010. Article 3 of this the regulator is to provide the utility with incentive to regulation establishes that: maximize its profits by minimizing the costs and allowing the utility to keep the cost savings achieved during the a. The annual electricity transmission price is uni- regulatory lag. formly applied at a national level regardless of the transmission distance and place of delivery. Volume 3: Regulatory and Performance Monitoring 247 b. The average transmitted power is determined b. Understandable: this means that the KPI defini- each year, according to the principle of ensuring tion relates clearly to the expected impacts of the full cost recovery and permitted profits to oper- Smart Grid application. ate the transmission grid according to the quality c. Quantifiable: this means that values derived regulations and to meet key financial targets for from their implementation and testing are used the investment and development of the transmis- to develop the status of their contribution to the sion grid. improvement of the network. c. The average annual transmission price is deter- mined on the basis of the total electricity transmis- Given the current transmission regulation in place, the sion revenues allowed for a year for the National KPIs proposed take account of 3 different types or Power Transmission Corporation and assigned to aspects (shown in Figure 112) for the evaluation of the the Unit that must pay the cost of power trans- success of the Smart Grid initiatives and their inherent mission at the point of delivery of electricity. level of smartness: The total electricity transmission revenues allowed annu- a. Technical: The performance indicators to mea- ally are referred to as the total capital cost for a year sure the success of the technical implementation allowed for the National Power Transmission Corporation4 of each Smart Grid initiative; plus the total cost of the operation and maintenance of b. Economic: The benefit/cost ratio values calcu- transmission allowed for the year plus the adjustment of lated in the Cost-Benefit Analysis; and revenues of the previous year. c. Regulatory: The indicators to measure how the The transmission regulation in Vietnam is close to a Rate- delay or the modifications in the installation steps of-Return regulation with a push for efficient costs to of each Smart Grid initiative affect its benefits. be approved by ERAV. In this schema overall cost of the Each aspect also considers the project level, Smart Grid transmission activity plus a return are fully recognized by program implementation level and system level for the regulation. So, there are no incentives except to avoid KPIs. penalties for quality indicators such as the annual target for Energy Not Served in MWh as defined by ERAV from On the other hand, each KPI could be tied to major objec- time to time5 and a losses target6 [6]. tives for the whole system and part of a regulatory energy policy. In this case, we assume that the main major goals On the other hand, it is important to consider the cur- of the system are: rent stage of the Vietnamese electricity market and the considerable gap between the SAIFI and SAIDI indicators relative to the mature power systems of developed coun- tries as previously reported7. FIGURE 112: KPI BY TYPE AND LEVEL Considering the previous statements and the regulatory approach for the transmission activity in Vietnam, the KPIs to be designed should only have a penalty mecha- nism if they exceed the approved values by ERAV. E.3 Design of the Key Performance Indicators for the Refined Roadmap In order to design KPIs for the Refined Roadmap, the fol- lowing characteristics should be considered: a. Meaningful: this means that a KPI relates to the expected innovation, impact, and there- fore makes sense since it is contributing to the Source: Authors achievement of the overarching goals. 248 Smart Grid to Enhance Power Transmission in Vietnam a. Enhancement of the transmission network E.4 Technical Key Performance reliability; Indicators b. Increase the Security of supply; and As stated in the technical analysis and in the previous c. Sustainability of the power system. chapter, the metrics for the technical evaluation of each Smart Grid initiative implementation are as follows: The KPIs mapped to those major objectives are pre- sented in Table 79. a. Fault Locator System. In order to evaluate the success of the FLS initiative, it is important to Each proposed KPI mapped to general objectives will measure the reduction in the time taken for the have a defined value in the appropriate range. The values intervention of maintenance crews during an out- in the range are derived from international best practices and age event. The FLS application will be considered the Consultant’s experience8. They were part of the assump- satisfactory if after its implementation such times tions in the developed model for the cost benefit analy- are reduced by at least 25%. sis. The details are presented in the following paragraphs. b. Wide Area Monitoring System. The evalua- In order to effectively track these KPIs and the pace of tion of the success of WAMS initiative is a very implementation of the Smart Grid initiatives, some sta- complex area and entirely contingent upon the tistics are required to be gathered by NPT. This proposal applications and functions developed using PMU is presented in the next chapter. data. For example, an evaluation of a voltage TABLE 79: MAP OF KPIs WITH MAJOR OBJECTIVES Major Objectives Enhanced Reliability of transmission Security of Smart Grid Initiative KPI describing the expected improvement network Supply Sustainability Reduction of time to attend fault site by Fault Locator System X X X maintenance crew and elapsed time to repair Voltage collapse prevention X Wide Area Monitoring System Out-of-steps prevention X Energy Not Served (ENS) reduction per year for Substation Automation System X X X each substation equipped with SAS Percentage reduction of transient faults Lightning Location System X X affecting the lines Mean square error between the value acquired Metering Data Acquisition System by the meters and the value calculated by the X settlement for the same meters 95% variation interval of voltage level of X X X Static Var Compensator network “pilot nodes” Voltage collapse prevention X X X Geographic Information Systems Reduction of management costs X Power quality monitoring system Percentage reduction of voltage dips X High Voltage Direct The reduction of power losses X Current technology High power factor X On-line Dissolved Gas- Fault number reduction X X in-oil Analysis Dynamic Thermal Circuit Rating “Ampacity” increase X X X Source: Authors Volume 3: Regulatory and Performance Monitoring 249 stability-monitoring feature based on WAMS may i. High Voltage Direct Current technology. To be considered successful if it is instrumental in evaluate the success of an HVDC link installa- preventing 15%-35% of voltage collapses. The tion it will be necessary to measure the power actual percentage gains depend on the topology losses and the load factor on the line. In order of that portion of the network involved in the volt- to effectively reduce the power losses (not only age instability event. Equally, an evaluation of a in percentage terms but also in absolute terms) transient stability monitoring function on WAMS the line has to be fully exploited, making it carry might be considered successful if it helps to a large amount of power (this is a key feature of prevent 15%-35% of power plants falling out-of- HVDC technology which has the potential for step. As with the voltage collapse case the actual enormous bandwidth). Therefore, for evaluating percentage gains depend on the topology of the if the choice of a DC link instead of an AC line portion of the network involved. has been successful, the load factor represents the crucial technical KPI. A value above 0.7 can be c. Substation Automation System. The key per- considered satisfactory. formance indicator (KPI) for the evaluation of such an initiative is the reduction of Energy Not Served j. On-line Dissolved Gas-in-oil Analysis. The DGA (ENS). A SAS implementation will be considered installation initiative can be considered success- successful if the reduction in the average value of ful if the use of the monitoring systems consis- Energy Not Served (ENS) per year for each sub- tently results in the prevention of transformer station equipped with SAS is above 100MWh. outages. A reduction by 80% in the number of faults could be considered a satisfactory value. d. Lightning Location System. The installation of Transmission Surge Line Arresters (guided by k. Dynamic Thermal Circuit Rating. According to Lightning Location System data analysis) will be international experiences, which are also borne considered successful if it results in a 20%–30% out by the Vietnamese Smart Grid roadmap, the reduction of transient faults. dynamic ratings are typically 5% to 25% higher than conventional static ratings. So, if on the lines e. Metering Data Acquisition System. To evalu- where the DLR is applied the “ampacity” increases ate the success of the Metering Data Acquisition from between 5% to 25% the results of DLR System it will be necessary to measure the mean implementation will be considered satisfactory. square error between the value acquired by the meters and those used in the original base- The proposed KPI metrics for the technical evaluation of line calculated by the settlement for the same each implemented Smart Grid initiative are summarized meters. A satisfactory value will be in the range Table 80. from 0.4%-0.8% interval. f. Static Var Compensator. To evaluate the perfor- Apart from the preceding technical metrics it is also mance of the SVC system it would be appropri- important to have the following statistics in order to bet- ate to measure the variation of the voltage level of ter evaluate the impact of the Smart Grid implementation the most important network nodes (named “pilot and to determine some of the previous technical KPI: nodes”). If 95% of such variations are within +/-5% of the rated voltage the result could be considered a. MW of transfer capacity of HVDC link. satisfactory. Furthermore, as for the WAMS evalua- b. Interconnection Capacity increase (MW) between tion, a SVC may be considered to be operating suc- transmission system and Distribution Systems cessfully if it is key to preventing 15%-35% of before and after the implementation of a Smart voltage collapse in effected parts of the network. Grid application. g. Geographic Information Systems. In order to c. Interconnection Capacity in MW of direct current evaluate the success of the GIS application it will flowing between neighboring countries and the be necessary to measure the reduction in the Vietnamese Interconnected system (not isolated cost of managing the energy network. A satisfac- areas). tory value for such a reduction will be in the range of 10%–15%. d. The number of events that result in brownouts and blackouts. The Energy Not Served associated h. Power quality monitoring system. A suitable KPI with every event and discriminated by type of is the percentage reduction of voltage dips where a users affected, i.e. industrial zones in particular value above 20% can be considered satisfactory. as well as others. 250 Smart Grid to Enhance Power Transmission in Vietnam TABLE 80: TECHNICAL METRICS IDENTIFIED FOR SMART GRID SOLUTIONS Technical KPI Satisfactory Smart Grid Initiative Performance indicator threshold Reduction of time to attend fault site by maintenance crew and Fault Locator System 25% elapsed time to repair Voltage collapse prevention 15%-35% Wide Area Monitoring System Out-of-steps prevention 15%-35% Energy Not Served (ENS) reduction per year for each substation Substation Automation System 100MWh equipped with SAS Lightning Location System Percentage reduction of transient faults affecting the lines 20%-30% Mean square error between the value acquired by the meters Metering Data Acquisition System 0.4%-0.8% and the value calculated by the settlement for the same meters 95% variation interval of voltage level of network “pilot nodes” +/-5% of the rated voltage Static Var Compensator Voltage collapse prevention 15%-35% Geographic Information Systems Reduction of management costs 10%-15% Power quality monitoring system Percentage reduction of voltage dips 20% High Voltage Direct Power factor 0.7 Current technology On-line Dissolved Gas- Fault number reduction 80% in-oil Analysis Dynamic Thermal Circuit Rating “Ampacity” increase 5%-25% Source: Authors e. A table with the details of the disconnected E.5 Economic Key Performance loads, value of the demand disconnected (MW), Indicators the duration of the disconnection should be elaborated in order to determine the Energy Not The Cost-Benefit Analysis calculated some indicators to Served of each event. An analysis of the precise evaluate the economic success of the investment in the cause of each event of the Vietnamese power proposed Smart Grid initiatives and these can be consid- system stability (which resulted in either brown- ered as the economic targets to be achieved. outs or just an event without any transmission component disconnected) The classification of The B/C ratio values of the various Smart Grid initiatives each Power System Stability event should follow are listed in descending order by value in Table 81. the classification shown in Figure 113. f. Determine if the event can be analyzed in terms These KPIs are for those applications that produced the of the precise cause/s using the installed WAMS. best results in the economic analysis. During the imple- mentation of the Smart Grid initiatives, the cost benefit g. For each event determine the last time that the ratio must be tracked and compared with the baseline N-1 analysis was conducted (months, days, min- values listed in the table above. Any reduction of the ratio utes, etc.). will be considered indicative of the increasing costs of the initiative. Volume 3: Regulatory and Performance Monitoring 251 FIGURE 113: CLASSIFICATION OF POWER SYSTEM STABILITY EVENTS Source: IEEE / CIGRE, 2003, (2) Note: Voltage Stability is also called Voltage Collapse. TABLE 81: SUMMARY OF THE SYNTHETIC VALUES OF THE ECONOMIC BENEFITS OF SMART GRID INITIATIVES Smart Grid Initiative Economic KPI Power quality monitoring and Metering Data Acquisition Systems B/C ratio: 39.26 Dynamic Thermal Circuit Rating B/C ratio: 35.11 Wide Area Monitoring System B/C ratio: 17.82 Lightning Location System B/C ratio: 6.89 Geographic Information Systems B/C ratio: 3.61 Substation Automation System B/C ratio: 2.13 High Voltage Direct Current technology B/C ratio: 1.56 Static Var Compensator B/C ratio: 1.21 Fault Locator System B/C ratio: 1.17 On-line Dissolved Gas-in-oil Analysis B/C ratio: 1.13 Source: Authors E.6 Regulatory Key Performance a. At an individual level, an indicator that measures Indicators the pace of implementation for the approved initiative. From the point of view of the regulatory perspective the b. At an individual level, an indicator that measures success of each Smart Grid initiative can be evaluated the gap between an acceptable cost-benefit ratio using the following indicators: (considering the possible delays and likely new 252 Smart Grid to Enhance Power Transmission in Vietnam conditions), with respect to the baseline pre- e. At the program level, a Smart Grid Effectiveness sented in the approval stage. Index based on a weighting for each initiative launched and result obtained. The Regulatory c. At the system or program level, an indicator that Authority should assign the proper weighting for measures the number of Smart Grid initiatives each initiative. launched in the short-term over the total number of planned initiatives in the short-term. Those indicators will only apply after the approval of the proposed refined roadmap. d. At the system level, an indicator that measures the results delivered by the Smart Grid initiatives in the short-term. F. Revision of the Legal and Regulatory Framework F.1 Key Points Summary F.2 The Legal Framework This chapter presents a review and analysis of the Legal The regulatory framework in Vietnam has changed quite and Regulatory framework, highlighting the changes significantly in the last ten years as it has sought to that have occurred over the last ten years in Vietnam’s consolidate and develop an electricity wholesale mar- electricity market. The purpose of this analysis was to ket commensurate with the fast growing demands of determine the aspects and policies currently in place that the country. At the time of passing the Electricity Law, impact the Smart Grid policy. Vietnam had a peak demand of 8.3 GW and an installed capacity of 10.6 GW [7]. In 2013 the peak demand The following policies were analyzed: reached 20 GW while the installed capacity was 30.4 GW with a further significant increase in the offing. a. System Security policy; The introduction of the Electricity Law allowed the diver- b. Renewables and their policies and incentives; sification of investments (see Figure 114), in the power c. International Interconnection policy; sector facilitating the participation of all economic sec- tors. The Law also created the electricity market and d. Quality of Service regulatory policy (indicators, stipulated the step-by-step development of competitive incentives, penalties); generation as well as wholesale and retail competitive e. Smart Grid Policy; and markets. f. General policy for investment incentive in trans- These antecedents and the development of the sub- mission and recovery mechanism. sequent legal framework based on the Electricity Law of 2004, is analyzed in the light of the main Decisions Finally, recommendations for the implementation of the passed by the Regulator and/or the Ministry. Refined Roadmap are performed as well as a definition of the roles and responsibilities of the stakeholders. FIGURE 114: INSTALLED CAPACITY AND ENERGY PRODUCTION IN 2013 Source: Authors 253 254 Smart Grid to Enhance Power Transmission in Vietnam FIGURE 115: TIMELINE AND OVERVIEW OF THE LEGAL FRAMEWORK OF VIETNAM Decree SMART GRID 137/2013/ND -CP ROADMAP ¥ Amendment of the Decision Decision Electricity Law 24/2014/ QD -TTg Decision 1670/ QD -TTg ¥ Implementation of March 2014 Amendment to 153/2008/ QD - November 2012 some provisions Planning and Full the Electricity TTg of the Electricity development of Market Law Law Biomass Operation 2004 2005 2008 2011 2012 2013 2014 2016 Electricity Law. Decision Decision 63/2013/ QD -TTg 37/2011/ QD -TTg The Law N _. Regulations to Pilot form and develop Market 28/2004/QH11establish the Mechanism to legal framework for support the coal electricity Operation market cap. Vietnamese Electricity development of Market. wind power projects in Vietnam Source: Authors A timeline and overview of the electricity legal framework Our analysis shows that the Electricity Law has implica- is presented in Figure 115. The green box represents tions for developing policies on renewables, new tech- the Decisions passed in Vietnam regarding renewables, nologies, the energy market and competition in general. while the orange box represents the Decision regarding Further, it establishes the transmission of energy as a the Smart Grid initiatives, which was passed in Novem- monopolistic activity to be performed exclusively by the ber 2012. State of Vietnam. The legal framework directly or indirectly affects the In particular, the third paragraph of Article 4 addresses development of a Smart Grid policy. The major mile- the development of a Smart Grid policy: “… apply sci- stones in market development, depicted above in Figure entific and technological advances to electricity activities 115, are also important and they were factored into the and use with a view to saving, raising the efficiency of final prioritization of the proposed Smart Grid strategy using various energy sources, protecting the ecological roadmap. environment” . The next paragraphs will analyze the most significant It is clear that the highest-level legal instrument in the land Decision for the development of a Smart Grid policy. addresses itself specifically to the development of both a Smart Grid policy and a sustainable Renewables policy. F.3 The Electricity Law Turning to the subject of the reliability and security of the electrical system, Article 40, point 2, paragraph a) of The narrative presented below analyses Electricity Law the Electricity Law mandates the following obligations No. 28/2004/QH119, passed in 2004, with a particular for energy transmission activities: “a) To ensure the safe, focus on Article 4, and some of the key policies that were stable and reliable operation of the electricity grids and subsequently developed. electricity transmitting equipment.” The level of detail of the policies contained in the law is The same Article and point establishes that the obligation adequate following the traditional Kelsen pyramid of the of the Transmission operator is progressive and far reach- juridical framework. The Electricity Law is the appropriate ing “…to draw up plans for investment in development base to develop the next juridical level, which is com- of the electricity transmission grids and invest in the prised of the bylaws and/or Decisions in order to imple- development of electricity transmission grids to satisfy ment these policies for the electricity sector. the electricity transmission demands under the electric- ity development planning; to invest electricity-measuring or -counting equipment as well as support equipment…. ” Volume 3: Regulatory and Performance Monitoring 255 Thus, the mandates of the Electricity Law provide more Article 6 also establishes that transmission companies than enough grounds for the development of a Smart are responsible for building plans, roadmaps for renova- Grid by NPT, the legally nominated transmission operator. tions, current line upgrades, transmission substations It is recommended that the NPT’s plan include the Smart and power distribution stations compliant with national Grid applications with a positive cost-benefit analysis in or comparable international technical regulations and order to develop a reliable network and apply “techno- standards. logical advances” as required by the Law. Article 15 defines some qualitative standards and bench- The regulatory body (ERAV) is responsible for the analy- marks for the voltage and frequency of the electric sis, approval and oversight10 [8] of the investments that system: the transmission operator (NPT) has to make in order to comply with the legally binding requirement to pre- a. “About voltage: In normal conditions, the permit- vent both sustained interruptions and major events ted difference of voltage is about ± 5% in com- (blackouts). parison with the nominal voltage of the power grid and defined at positions where equipment for electricity metering is laid or other positions F.3.1 Decree No. 137/2013/ND-CP as agreed by two parties. For a power grid which This Decree details the implementation of several articles has not stabilized to a steady state following an of the Electricity Law regarding planning and investment incident, the permitted difference of voltage is in electricity development. It addresses many aspects of from +5% to -10%; electrical power from the management of demand, sales b. About frequency: In normal conditions, the per- and purchases, prices, activity licenses, regulation and mitted frequency difference of the electrical sys- inspection activities to usage. tem is about ± 0,2Hz in comparison with nominal frequency of 50Hz. For a power grid which has According to this Decision, the Ministry of Industry and stabilized to a steady state following an incident, Trade is responsible for the planning of electricity devel- the permitted frequency difference is ± 0,5Hz” . opment, guidance on planning annual electricity invest- ment and for development on the basis of the approved The Article finishes by establishing a market for reactive plan for electricity development. power when cos φ < 0.9. The Ministry is also responsible for announcing the On the other hand, Article 22 addresses the sale and national master plan on electricity development, includ- purchase of electricity to/from foreign countries. It states ing the amended master plans that have already been that those authorized as competent to permit the sale approved. and purchase of electricity with foreign countries include: Article 5 of this Decision establishes the demarcation a. The Prime Minister who shall approve policies for limits for the construction of a transmission infrastruc- the sale and purchase of electricity with foreign ture. This Article decrees that the transmission and distri- countries through the national power grid at a bution companies are responsible for investment in the voltage of 220 kV or more. The Ministry of Indus- construction of switching stations, substations, stations try and Trade shall consider proposals for the sale for reactive power compensation within their manage- and/or purchase of electricity with foreign coun- ment remit, unless otherwise agreed. This means they tries measured in electricity units, and submit are responsible for enhancing the transmission network them to the Prime Minister; using, if they wish, Smart Grid technology (according to Article 4 of the Electricity Law). b. The Ministry of Industry and Trade shall approve policies for the sale and purchase of electricity Article 6 of the Decision establishes that the power with foreign countries through the national power lines, transmission substations and new power distribu- grid at voltages of less than 220 kV measured in tion stations must be designed with and use technical electricity units. equipment and technologies in line with technical regu- Articles 5 and 6 of the Decision clearly allocate the lations and national standards (Vietnam’s standards), or responsibility for investment in Smart Grid technology to foreign standards which are equivalent or higher and are the transmission companies. This emphasizes the gen- permitted by competent state agencies for application in eral policy established in the Electricity Law. Vietnam. 256 Smart Grid to Enhance Power Transmission in Vietnam F.4 Regulatory Framework consideration to the costs and quality of supply prefer- ences of all Users. In order to have a complete overview of the regulatory framework it is important to review the Decisions of the It is recommended that ERAV ask for a cost-benefit anal- Ministry and the Regulatory Authority regarding the secu- ysis in order to improve the MWh target of un-served rity and reliability of service (prevention of blackouts), the energy instead of guidance on cost levels. The decision long-term planning of the transmission network (Smart has to be taken by the regulatory body for the overall Grid), the Decisions mentioned in the Vietnamese Road- electricity system taking account of the willingness of map as well as those regarding the regulation of fre- the users to pay and the Value of Lost Load (VoLL). quency and others identified in the Task-1 Report. The setting of this regulatory target as a part of the Reli- ability Standards is a key point to incentivize the develop- F.4.1 Grid Code ment of Smart Grid technologies in order to improve the The Grid Code has 13 chapters and the main ones rel- yearly MWh not served in order to reduce the regular evant to this study are as follows: transmission outages and major events such as black- outs. Without this target, there is neither the pressure a. Chapter III—Power System Performance nor incentive for the TNO to implement a more aggres- Standards; sive policy in order to solve the existing problems and improve the reliability of the system. b. Chapter V—Network Planning; c. Chapter VI—Power System Operation; and Article 25 of the Code establishes the maximum Short Circuit Current and Fault Clearance Times. The maximum d. Chapter IX—Performance Indicators. short circuit current for the 500 kV and 220 kV is 40 kA. This value should be updated for some substations in F.4.1.1 Chapter III - Power System Performance Standards order to support higher currents (50 kA) in some parts of the network. This will lend support to the argument Chapter III lays out the power quality performance stan- in favor of the technology for the “pillars” as defined in dards that the System Operator and Transmission Net- Task-1, which will enable Network Planning to limit these work Operator are aiming for when operating the power values. system. One of the important topics to consider is voltage dips. Article 19 defines the System Frequency and the upper The common cause of this phenomenon is temporary, and lower limits, and Article 53 details the requirements intermittent loss of supply typically caused by short of the power plant governors. Nevertheless the Grid circuits, load switching, network switching and power Code does not mention anything regarding the second- swings. These phenomena have a significant impact on ary and tertiary regulation and the limits established for the operation of industry, manufacturing and mining plant the frequency of these aspects. It is worth highlighting machinery, which depends on a steady, consistent power the importance of having a rigorous frequency regulation supply. Dips in the supply voltage (depressions in supply for the power system. This includes the generation units voltage of short duration) can lead to unnecessary stop- as well as the primary, secondary and tertiary systems. page of plant processes unless adequate measures have been taken in the design of their electrical equipment. The Grid Code is lacking on this important aspect and must be complemented. This will also enable one of the Given the current status of industrial development in basic pillars presented in the Task-1 Report. Vietnam as well as the concerns of the Industrial Zones Management Authority [9] for the 800 industries, there is This chapter also establishes the Reliability Standards an urgent need to improve the overall quality of service and the annual target in MWh defined by the regulating by addressing the issue of voltage dips in the Grid Code. authority (ERAV) for the annual un-served energy. The recommendation is to complement the quality of According to Article 22, in order to establish an annual performance of the Grid Code regarding voltage dips in target ERAV shall i) consult with the Transmission Net- order to avoid interrupting power supply to the manu- work Operator (TNO), System Operator (SO) and all facturing industry. Smart Grid technology solutions have Users; ii) seek advice from the TNO on any impact on been used in other countries to successfully reduce or transmission costs of a proposed target; and iii) give due even eliminate voltage dips. Volume 3: Regulatory and Performance Monitoring 257 F.4.1.2 Chapter V - Network Planning analyze and announce the total projected usable capacity and load together with system security requirements in According to Article 77, the TNO is responsible for invest- the medium and short term. ” ment in the transmission network to: Nevertheless, one of the most important components a. Support the current approved national power missing from this assessment is on-line security. In order development plan, regional power development to perform the task required by Article 92, on-line secu- plan as well as any current connection contracts; rity is a fundamental requirement. This topic was fully b. Meet the network performance criteria in Articles addressed in the “pillars” in the Task-1 Report. 22 to 33. In addition, what is missing from the Grid Code regula- The provisions established in the Grid code allow the tion is the obligation of the System Operator to have the TNO to invest in sustaining performance levels of: proper tools in order to evaluate all the parameters as well as perform on-line monitoring and control of the volt- a. Reliability Standards; age/dynamic stability of the Vietnamese Power System. b. System Loss Standards; A complementary point in this chapter will help the Sys- c. Voltage Unbalance; tem Operator to acquire the most up-to date technology in order to properly monitor and control the operation of d. Short Circuit Current and Fault Clearance Time; the electrical system. e. Harmonics; This will also facilitate the introduction of Smart Grid tech- f. Voltage Fluctuations and Flicker Severity; nologies like WAMS and all the associated applications. g. Ground Fault Factor; h. Neutral Grounding; and F.4.1.4 Chapter IX - Performance Indicators i. System Voltage. This chapter of the Grid Code presents the performance indicators that apply to the System Operator (7) and to The regulation allows the TNO to invest in Smart Grid the TNO (6 groups). technologies in order to maintain the standards and avoid the problems mentioned above. These investments are It is worth highlighting that the indicators proposed require in addition to the Approved National Power Development declaring the un-served energy for each unplanned event Plan. The requirement is approved by the regulatory as well as the total number of unplanned interruptions in authority (ERAV). excess of 1 minute. Nevertheless, these indicators do not take account of F.4.1.3 Chapter VI - Power System Operation using the appropriate methods or tools to investigate the The operational issues, responsibilities and obligations of causes that led to a blackout. It is not adequate to state the System Operator (NLDC) are clearly described in this that the cause of the blackout was a tree falling across chapter. a transmission line or a tripped relay. It is important to assess how the original event led to a significant system Article 92 establishes that the System Operator is respon- wide black-out and properly diagnose the power sys- sible for providing security constrained economic dispatch. tem phenomena that are involved in the knock-on effect Further, Article 112 mentions the security constraints to be that causes a single, relatively trivial, event to propagate considered while ensuring economic dispatch. across the system. Once identified these single points of failure have to be eliminated with appropriate investment In Chapter VIII – An Outage Planning Process is mandated and commensurate procedures and practices. to ensure that the security of supply can be maintained throughout the two years and for the following 12 months. The indicators of unplanned interruptions must be inves- The Outage Planning Process will be achieved by conduct- tigated to discover the real causes of a blackout (voltage ing medium and short-term security assessments. collapse, transient instability, etc.) so as to determine what measurements and measures the TNO could have The Grid Code defines System Security Assessment as taken in advance in order to prevent those interruptions. a “process, based on available data and information, to 258 Smart Grid to Enhance Power Transmission in Vietnam From the interviews performed in Vietnam is clear that responsible for announcing, monitoring and controlling both the SO and the TNO do not have the proper tools the execution of the approved national plans for wind in order to either trace the real causes of an event or to power development. prevent it. The People’s Committee of those centrally-affiliated cit- ies that have a potential for wind power development are F.4.2 Smart Grid Roadmap tasked with organizing the planning of wind power devel- The Vietnamese government issued Decision No.: opment at a provincial level and to then submit their pro- 1670QĐ-TTg in November 2012 approving a national posals to the Minister of Industry and Trade for approval. Smart Grid development. The investors in Wind power projects that are not on The Decision specifies both general and specific targets the list of nationally approved wind power development for the Smart Grid roadmap: schemes are responsible for submitting proposals on supplementary systems to the Ministry of Industry and a. General target: Develop a Smart grid with high Trade who will evaluate and submit them to The Prime technology support in order to improve the qual- Minister’s office for consideration and final decision. ity and reliability of the national power supply; contribute demand side management, encourage Article 7 of this Decision states that the connection of energy saving measures and efficiency; create Wind power projects to the national electricity grid must favorable conditions for the improvement of labor be part of the approved plan for development. The con- productivity, reduction of investment demand nection point is agreed by both the electricity seller and on generation and power network; enhance the purchaser on the understanding that the electricity seller rational exploitation of energy resources, ensure has the responsibility for investment in the transmission national energy security, contribute to environ- line/s to the connection point/s of the national electricity mental protection and sustainable socioeco- grid which should be the nearest to the planned site for nomic development. the provincial electricity development. b. Specific Target: the list of Smart Grid initiatives The mechanism for supporting wind generation (Article mentioned in the preceding sections. 11) states that the electricity purchaser is responsible for the wholesale purchase of the electricity produced from The Decision establishes the general target but without grid-linked wind power plants in a given area. Electric- mentioning the specific legal support for the Decision ity trading is performed through a typical electricity trade such as particular articles of the law and the regulatory contract overseen by the Ministry of Trade and Industry framework. and is based on the following: The Decision also does not consider the incentive mech- a. Contract Period of twenty years from the com- anism, the remuneration for those initiatives, the cost- mencement date of the trading operation. The benefit analysis or the metrics for each initiative. electricity seller may extend the contract period or sign a new contract with the electricity pur- F.4.3 Decision on Renewables chaser according to the regulations. b. The Base Price for purchasing electricity and the F.4.3.1 Decision No. 37/2011/QD-TTg principle for adjusting the Price of selling electric- Decision No. 37/2011/QD-TTg on 29 June 2011 focuses ity at contract renewal time. on the development of Wind Power Projects in Vietnam. c. Agreement regarding connection, measurement and operation of the wind power plant. The Decision emphasized the planning mechanisms and processes of wind power projects rather than incentives Wind power projects enjoy preferential import tax relief to promote wind power generation. as well as preferential enterprise income tax relief. Wind power projects are exempt from import tax for goods and Article 4 of the Decision establishes that The Ministry of have a reduced enterprise income tax. Industry and Trade organizes the planning for wind power development, which is then submitted to The Prime Article 14 establishes a price for grid-tied wind power Minister for approval. The Prime Minister’s office is also projects. The electricity buyer has responsibility for Volume 3: Regulatory and Performance Monitoring 259 buying output from wind power projects at the point b. The development of the power transmission of electricity receipt at a wholesale rate of 7 .8 $cents/ grid (efficient use of energy - i.e. Smart Grid kWh or its equivalent of 1.614 Dong/kWh (without VAT). technologies); The electricity purchase price is adjusted by the current c. Interconnection of power networks with neigh- exchange rate between the Dong and $. The government boring countries; and of Vietnam supports the electricity price for the buyer of wind power generated power at the rate of 207 Dong/ d. Electricity supply to rural, mountainous and island kwh (equivalence 1.0 $cents/kWh) through the Vietnam areas. Fund for Environment Protection. The Plan emphasized a balanced development of power The final price, subsidized by the government, is 6.8 $cents/ sources in each region of Vietnam (North, Central and kWh while the average approved electricity tariff is South) to ensure the power reserve capacity is evenly approximately 7 .6  $cents/kWh (1,509 Dong/kwh) [10]. shared and reliable for each region. According to the Plan, According to the Asian Development Bank the tariff of the aggregate power generation capacity of all the power 1,500 Dong/kwh is lower than the long-run marginal cost plants in Vietnam will increase to about 75,000 MW by estimated to be in the range of 1,7001,900 Dong/kwh. 2020 (with produced and imported electricity of 330 bil- lion kWh) and 146,800 MW by 2030 (with produced and These positive aspects are designed to encourage imported electricity of 695 billion kWh). the introduction of energy generation from renewable sources in Vietnam and are intended to act as an incen- According to the plan, fossil fuel will be the most impor- tive for their development. The less attractive aspect is tant source of electricity in Vietnam in the medium and that the agreement is always based on a typical contract long-term. Power generation capacity from this source and the final decision probably lies, yet again, with the will rise from 21,000 MW in 2010 (which saw the produc- Ministry. tion of 100 billion kWh) to 36,000 MW in 2020 (predicted ~156 billion kWh output) and to 75,000 MW in 2030 (pre- Further, the planning mechanisms and approval cycles dicted ~394 billion kWh output). As the current domes- are controlled by the Prime Minister’s office and the Min- tic coal supply is insufficient, importing coal from nearby istry of Industry and Trade. This arrangement requires countries is accelerating and new coal-fired generation more flexibility in the market environment in order to plants using imported coal are required to start operating avoid bottlenecks. from 2015. The regulations require that the wind farm must be con- MP VII also gives top priority to the development of nected to the grid at the closest transmission grid con- power sources using renewable energy such as wind, nection point. The incentives for wind power generation solar and biomass power. The percentage of renewable motivate the investor to ensure that the grid connection energy power is projected to increase from almost zero point is reliable and this acts as an indirect spur to invest- to 5.6% by 2020 and 9.4% by 2030. The Plan aims to ments in more advanced technologies like the Smart Grid increase the combined capacity of all wind power plants initiatives. to about 1,000 MW by 2020 and 6,200 MW by 2030 to raise the percentage of wind power to 0.7% by 2020 and 2.4% by 2030. Further, Vietnam encourages the devel- F.4.4 An overview of the Power Master Plan VII opment of multi-functioned hydropower projects (flood On July 21, 2011 through Decision No. 1208/QD-TTg, control, water supply and power production) and the total the Prime Minister approved the seventh power devel- capacity of hydropower plants is anticipated to reach opment plan for the period 2011 to 2020 with a view 19,125 MW by 2020. towards 2030 (the Power Master Plan VII/MP VII). The Plan is based on the assumption of GDP growth at 7 The development guidelines include two keynotes as to 8% during the period 2011 to 2030 and the expec- follows; tation that electricity demand will grow by 12.1% per year (worst-case scenario), 13.4% per year (base-case a. Investing more in the national power transmis- scenario) or 16.1% per year (best-case scenario). MP VII sion grids in order to bring more power plants on- emphasized four main areas: line combined with an the overall development strategy for the power sectors and regions; a. The development of power sources (priority for renewable energy development); 260 Smart Grid to Enhance Power Transmission in Vietnam b. Increasing the reliability of power supply, reduc- c. Phase 3: Vietnam Competitive Retail Market ing power loss and ensuring a favorable mobili- (VCRM). This phase will also be implemented zation of power sources between rainy and dry in two steps; first as a pilot competitive retail seasons and in all operation regimes of the power power market from 2022 to 2023 rolling over to market. a full competitive retail power market from 2024 onwards. According to the plan, the voltage level of 500 kV will still be the dominant superhigh voltage for power trans- In order to form the Vietnam Competitive Wholesale mission of Vietnam. There is a plan for further research Market, the power sector structure must satisfy the two on the development of transmission networks at voltage following conditions: levels of 750 kV, 1000 kV and by high voltage direct cur- rent transmission systems after 2020. a. Firstly, during the pilot wholesale market phase, the National Load Dispatch Center and Power The Master Plan also establishes that grid moderniza- market administrator must be kept as indepen- tion should be performed gradually. The renovation and dent units that have no common interests with upgrading of switchgear, protection and automation stakeholders participating in the power market. of the grid, research on using FACTS, SVC devices to The Power Generation Corporation and power increase the transmission limits and a step-by-step mod- plants under the Electricity of Vietnam (except ernizing of the control systems. MP VII also references for big power plants that have special roles in the research on developing “Smart Grid” technology, supporting the local economy, national defense making the interaction between household consump- and security, which are managed by the State’s tion, industrial equipment and the electricity grid capa- monopoly as stipulated in Article 4 of the Elec- ble of exploiting the most effective approach to energy tricity Law) shall be split into independent power supply while reducing the cost of grid development and generation units which have no common inter- improving the security of the power supply. ests with bulk power units or with transmission units. The National Load Dispatch Center will act MP VII places some emphasis on thermal coal-fired as the Power market’s transaction administrator. power development and renewables. The plan refer- ences Smart Grid technology in the context of modern- The total installed capacity of a power generation izing the grid with a focus on research of FACTS, SVC unit shall not exceed 25% of total installed capac- and other technologies in order to improve the security ity of units participating in the Power market. of power supply. The Power Corporations and the Power Compa- nies, which satisfy the aforementioned condi- F.4.5 Electricity Market Roadmap tions, will be selected for participation in the pilot and full wholesale market. There must be a clear Decision No. 63/2013/QD-TTg, dated 8 November 2013, demarcation between the organizational and made by the Prime Minister’s office, presents an Electric- cost-accounting functions of the power distribu- ity Market Roadmap defining the conditions and structure tion and the power retail units. of the electricity generation and transmission system to shape and develop the electricity market in Vietnam. b. Secondly, in the full competitive market, Power companies under the Power corporations should The Decision defines a three phase gradual approach as be organized into independent cost-accounting follows: units, which must be demonstrably separated from the cost-accounting functions of the power a. Phase 1: Vietnam Competitive Generation Mar- distribution and the power retail departments. ket (VCGM). Requires that competitive power generation be continued until the end of 2014; In order to form a competitive retail market, the power sector structure is required to satisfy the two following b. Phase 2: Vietnam Competitive Wholesale Market conditions: (VCWM). This phase will be implemented in two steps; first as a pilot competitive wholesale mar- a. During the pilot phase for a competitive retail ket from 2015 to 2016 rolling over to a full com- market, retail departments of several Power com- petitive wholesale market from 2017 to 2021; panies, which satisfy conditions for participation in the pilot competitive retail market as stipulated Volume 3: Regulatory and Performance Monitoring 261 FIGURE 116: MARKET ROADMAP PHASES Source: Authors must be split into independent cost-accounting This requires the Electricity Regulation Bureau to advise power retail units. the Ministry of Industry and Trade on regulations for the safe, stable and secure operation of the electricity gener- b. In the full power retail market, the retail depart- ation infrastructure combined with the use of electricity- ments of the power corporation shall be split into saving and effective equipment. independent cost-accounting retailers. The Authority’s duties, includes submissions to the Indus- The market roadmap is shown summarized in Figure try and Trade Minister in order to approve or issue regula- 116. It has been and will continue be executed by ERAV tions as well as to establish electricity prices from the [11]. The Pilot VCGM was launched on July 1, 2011 and Government and the Prime Minister. It also includes sub- the Full VCGM was launched on July 1, 2012 with the missions to the Minister of Industry and Trade to approve participation of electricity generators representing or promulgate conditions, orders, procedures, appraisals approximately 35% of the total installed capacity of the and approval of the minimum cost plan, as well as regula- national system. tions on the condition and order to stop power supply. The details of the VCWM, the Market rules and the Mar- The Authority’s regulatory duties of the electricity market ket infrastructures are expected to be completed in 2015. includes appraisal of power development in provinces The expansion of competition at the wholesale level and cities, publicizing lists of transmission grid resource (VCWM), which will allow generators to sell electricity to projects according to the approved plans, supervising the multiple wholesale purchasers, including PCs and quali- planning of electricity resource development investment fied large customers is also expected in 2015. projects, transmission grids, general repair and mainte- nance, supplementing or withdrawing power operation F.4.6 Organizational Structure of Regulator licenses, issuing electricity price frameworks, setting transmission prices and the cost of using support services. The Prime Minister issued Decision No. 153/2008/QD- TTg on November 28th, 2008 to define the functions, The regulatory Authority is one of the key stakeholders duties, authority and organizational structure of the Elec- in the Smart Grid initiatives in Vietnam and has encour- tricity Regulatory Authority under the Ministry of Indus- aged the cost-benefit analysis for each of them in order try and Trade (MOIT). to foster the Vietnamese Competitive Wholesale Market. 262 Smart Grid to Enhance Power Transmission in Vietnam F.5 Topics that Impact the Regulation 92 of the Grid Code establishes that the System Operator of Smart Grids is responsible for undertaking security constrained eco- nomic dispatch. Further, Article 112 mentions the security In order to perform a review of the regulatory framework constraints to be considered in the economic dispatch. under the ambit of Smart Grids, the following areas have been identified and analyzed (Figure 117): Chapter VIII – The Outage Planning Process also estab- lishes the requirement to perform medium and short- a. System Security policy; term security assessments to ensure that the security of supply can be maintained throughout the two years and b. Renewables and their policies and incentives; the following 12 months. c. International Interconnection policy; Nevertheless, an important missing component is on- d. Quality of Service regulatory policy (indicators, line security assessment. In order to avoid repeating incentives, penalties); past errors it is important to introduce an on-line security e. Smart Grid Policy; and assessment process. This topic was properly addressed in the “pillars” in the Task-1 Report. f. General policy for investment incentive in trans- mission and recovery mechanism. As mentioned before, the Grid Code requires the System Operator to have the appropriate tools in order to evalu- The following will analyze the general impact that each ate the security and perform on-line monitoring as well policy may have on the Vietnamese Smart Grid policy. as having on-line control of the voltage/dynamic stability of the Vietnamese Power System. F.5.1 System Security Policy MP VII mentions the modernization of the grid and The System Security Policy was introduced in Chapter VII encourages research of FACTS, SVC and other technolo- of the Grid Code and analyzed in this document. Article gies in order to improve the security of power supply. FIGURE 117: POLICIES THAT IMPACT SMART GRIDS Source: Authors Volume 3: Regulatory and Performance Monitoring 263 Finally, Decision No. 1670QĐ-TTg for the Smart Grids Road- According to paragraph 4 of Article 4 of the Electricity Law map (November 2012) specifies in the General targets: No. 28/2004/QH11, one of the Electricity Development “Develop Smart grid with support of high technology in policies is to “step up the exploitation and use of sources order to improve quality and reliability of power supply…. ” of new energies, renewable energy for electricity genera- tion” and one of the measures to encourage and promote According to the previous framework and considering energy savings is by “Providing investment, electricity the frequency of the outage events suffered in Vietnam price and tax preferences as guided by the Finance Min- including blackouts, it is advisable to develop a separate istry to investment projects on development of power Policy in order to better guide the transmission author- plants using sources or new energy or renewable energy” . ity’s investments in Smart Grid technologies. Article 29 of the Electricity Law also establishes the Elec- This policy will have an important effect on the develop- tricity Price Policies and the creation of “conditions for ment of both the network and Smart Grid technologies various economic sectors to invest in electricity devel- as well as having an important impact at an external level opment with reasonable profits, energy resource saving, on enhancing the security and reliability of the system the use of various new energy, renewable energy” . in order to sustain the country’s industrial development. It will also have the additional benefit of attracting new From the previous regulation it is clear that the Electricity industrial investments as reported to Bloomberg by Law has several general provisions aimed at fostering a many sources from the Industrial Zones Management Renewable Energy Policy. These provisions set a policy Authority [9] [12] [13]. mechanism that supports the development of renewable energy and are quite well established in the context of the Kelsen pyramid. F.5.2 Renewable Energy Policy The renewables and their incentives policy is one of the Decisions about the development of renewables are most important topics that affect the Smart Grid initia- primarily focused on wind and biomass policies. The cri- tives and their development. A strong policy that incen- teria, methodologies and incentives established concen- tivizes the development of renewable power sources trate on planning procedures rather than on fostering and (larger plants rather than domestic rooftop installations assessing renewable energy investments. It is recom- for example) will increase penetration of renewable mended that the renewable policy for Smart Grid applica- resources and will have a significant impact on the per- tions of the refined roadmap is augmented to support the formance and reliability of the electricity grid. integration of renewables in the transmission network. The current inefficiencies of renewable power sources F.5.3 International Interconnection policy are largely due to their inherent variability compounded by the lack of large-scale economical storage capability. International Interconnections are addressed in Article 2 of the Electricity Law which states that “This Law applies Traditional planning for a power system and for expanding to organizations and individuals conducting electricity transmission functions has been undertaken in response activities, using electricity or engaged in other electricity- to the needs of the transmission system based mainly on related activities in Vietnam. Where the international trea- past and projected loading levels, which have traditionally ties which the Socialist Republic of Vietnam has signed been estimates of future demand. or acceded to contain provisions different from provi- sions of this Law, the provisions of such international In a market environment, and in the present case of using treaties shall apply” . different renewable energy sources (i.e., Differences in source and temporal characteristics, as well as in geo- The Law includes a provision that the treaties will prevail graphic location), transmission planning must respond to over the established in the law. This means that any treaty the needs of adequate reserve capacity in order to facili- for an international interconnection with different condi- tate the penetration of renewable sources. tions to those established in the Law may be applied. This introduces flexibility in order to perform international Vietnam is aiming for a full-deregulation of their whole- interconnections but, on the other hand, it generates sale market and the renewables policy is one of the main potential advantages and disadvantages for the electric- topics that needs further attention. The Smart Grid initia- ity market participants. International treaties may favor a tives and their policies will be significantly impacted by specific participant in comparison to the others, affecting the introduction of renewable sources. regular operation and dispatching in the market. 264 Smart Grid to Enhance Power Transmission in Vietnam Article 22 of Decree No. 137/2013/ND-CP addresses the The lack of penalties for the TNO weakens the case for sale and purchase of electricity from/to foreign countries. the introduction of Smart Grid technologies, which are It also identifies the authority competent to permit the being pushed (as presented in many references in Task-2) commercial trade in electricity with foreign countries: by the industrial user community who have a poor per- ception of the quality of service of electricity supplies. a. The Prime Minister who shall approve policies for the sale and purchase of electricity with foreign countries through the national power grid at volt- F.5.5 Smart Grid Policy ages of 220 kV or more. The Ministry of Industry Article 4, paragraph 3 of the Electricity Law No. 28/2004/ and Trade shall consider proposals for the sale QH1111, establishes the Electricity Development policies: and purchase of electricity with foreign countries “apply scientific and technological advances to electric- and submit them to the Prime Minister; ity activities and use with a view to saving, raising the b. The Ministry of Industry and Trade shall approve efficiency of using various energy sources, protecting the policies of the sale and purchase of electricity ecological environment” . with foreign countries through the national power grid at voltages of less than 220 kV at the request This principle established by Law can be applied in order of electricity business units. to properly develop a Smart Grid policy, which takes into consideration not only the criteria for development but No other provisions were found that could be applied to also the mechanisms i.e. the incentives and the remu- international interconnections, except for those quoted neration of the Smart Grid applications to be developed above. in the country. A clearer policy direction is needed regarding interna- As previously mentioned Decision No.: 1670QĐ-TTg in tional interconnections and this may have some signifi- November 2012 does not reference any remuneration cance for the development and deployment of some of and incentive mechanisms, penalties, cost-benefit analy- the Smart Grid initiatives, e.g., HVDC interconnection ses or any KPIs in order to track performance. and more stringent requirements for online monitoring and security assessment to ensure frequency/voltage Given the existing regulations governing the Smart Grid problems do not cascade from one system to another, roadmap and the provisions of Article 4 of the Electric- etc. A policy that addresses these points may facilitate ity Law, it is recommended that the Smart Grid develop- the inclusion of technologies like HVDC and to increase ment be augmented by the following: the use of SVC technology for maintaining the stability of the systems and link. a. The design of an incentive mechanism; b. The cost-benefit analysis of the initiative; F.5.4 Quality of Service Policy c. The metrics for each initiative; and In general, all the legislation that creates a de-regulated d. Penalties for significant brownouts and blackouts environment or introduces a market environment is in the electricity system. essentially dealing with quality of service issues. This is a consequence of the economic and regulatory theory that This mechanism should not simply provide the TNO with in order to control the quality of a product (electricity), cost recovery for their approved Smart Grid investments one must control the quality of the technical and com- but rather to add basis points that fundamentally incen- mercial services that support it. tivize utilities to invest in innovation. The most unambiguous signals of a quality of service The Vietnamese policy makers may want to take inspi- policy are effective mechanisms for incentives and/or ration from IRENA in the development of a policy that penalties. takes into account: The Vietnamese Electricity Law does not establish penal- a. Effective support must be comprehensive and ties or incentives for the quality of service. sustained and designed to minimize investment risks; The revision of the Grid Code also indicates that they do b. The effective support for policy development has not have penalties for quality of service. been performed in this study; Volume 3: Regulatory and Performance Monitoring 265 c. Effective and efficient support must balance sta- Further, Article 6 of Decree No. 137/2013/ND-CP states bility with adaptability; that transmission companies are responsible for building plans, roadmaps for renovating, for upgrading the exist- d. Stability is vital for creating investor confidence ing lines, building transmission substations and power in support mechanisms, otherwise, investments distribution stations in order to ensure compliance with may fail to take place or be more expensive due technical regulations and either national standards or to higher risks. Nevertheless, policies must be comparable foreign standards. able to adapt to changing circumstances and respond to as many signs from the investors as General policy for investment incentives in transmis- possible; sion and recovery mechanisms is established according e. Desired equity impacts can be achieved through to the legal framework. The approval of investments in sound policy design. This evaluation was per- Smart Grids or any other transmission initiatives is per- formed with the cost-benefit analysis presented formed by ERAV according to the Electricity Law and the in Task-2 and helped to identify equity impacts current regulations. and opportunities for improvement; The recovery mechanism for such investments is also f. Assessing institutional feasibility can inform pol- established in Article 31, second paragraph of the Elec- icy choices; tricity Law as follows: g. In order for a policy to operate successfully countries must have the requisite capacity to “The electricity generation prices, electricity- implement any given policy tool. Evaluations of wholesaling prices and charges for electricity institutional feasibility can help inform the choice transmission, distribution, electric-system regula- of policy tool and the investments that are needed tion, electricity market transaction administration, to enlarge policy options; support service expenses shall be formulated by the concerned electricity units and appraised by h. Evaluating replicability can help tailor policies to the electricity-regulating agency before they are country conditions; and submitted to the Industry Minister for approval”. i. Some factors that have led to success in one country may not be present in another. This type Circular No. 14/2010/TT-BCT from 15th of May 2010 of analysis can help identify investment policy describes the detailed mechanism to define the trans- adaptations that are important for good perfor- mission process as well as the recovery of the transmis- mance. It can also help set realistic expectations sion investments. The Circular clearly establishes that of policy outcomes. each year, according to the principle of ensuring full cost recovery and permitted profits, the operator must run F.5.6 General policy for investment incentive the transmission grid according to the quality regulations in transmission and recovery mechanism and to meet key financial targets for the investment and development of the transmission grid. According to the structure of the Electricity sector, the Directorate General of Energy (DGE) under the MOIT is A positive cost-benefit ratio is the most effective means responsible for energy planning and policy. of ensuring cost recovery of Smart Grid investments in transmission. The regulator will be able to approve the cost The Master Plan created by the Ministry of Industry and recovery under the current mechanism without any change Trade references development guidelines for transmis- or amendment to the current regulatory framework. sion networks and includes two key notes [14]: a. Investing more in the national power transmis- F.6 Recommendations for sion grids that will allow power plants to be brought on-line, within the overall development Implementation strategy of power sectors and regions; The willing and active participation of the main stakehold- b. Increasing the reliability of power supplies, reduc- ers is imperative to ensure a successful implementation ing power loss and ensuring a favorable mobili- of the Refined Roadmap. The stakeholders identified as zation of power sources between rainy and dry the main participants in the Refined Roadmap implemen- seasons and in all operational regimes of the tation are the following: power market. 266 Smart Grid to Enhance Power Transmission in Vietnam a. ERAV; recommended applications and it essential that they be encouraged to take a more active role in the process. b. NPT; c. NLDC; and Finally, as analyzed in the previous chapters, the Elec- tricity Law provides a basic legal framework in order to d. IE. introduce new technologies (Smart Grid initiatives) in the power system. These legal provisions in the Electricity The regulatory body has the lead role in approving the Law will be adequate to foster the development of Smart Refined Roadmap and enforcing its application. NPT and Grid technologies in a market environment consisting of NLDC are major influencers particularly from a technical an experienced and mature electrical sector. and economic perspective. Given the approved Roadmap, the perceptions from the Each stakeholder has two dimensions to their role in the workshops and interviews and the consultant’s experi- approval and execution of the roadmap: ence in similar cases, the manner in which the Smart Grid initiatives have been introduced in Vietnam, i.e. a. Commitment; and by Government Decision, is the most appropriate and b. Role and Importance of the Stakeholder to indeed the recommended approach. Success. For this reason, is important to complement this Decision The importance of the NPT to the ultimate success of with a detailed policy in order to establish clear economic the Smart Grid initiatives makes it imperative to increase and technical advantages that can bring about increased their actual commitment. However, the perceived com- benefits and performance. It is also recommended that mitment of middle management is also considered rel- a Smart Grid Committee be created to both oversee and evant to the overall success of the Smart Grid initiatives. ensure the success of the Smart Grid initiatives. This approach (Figure 118) will do much to reduce the risks associated The NLDC who are major influencers have an impor- with the introduction of new technologies and smooth tant role in the implementation of some Smart Grid the way through the multi-layered approvals process. FIGURE 118: REFINED ROADMAP MILESTONES FOR IMPLEMENTATION Presentation Task-1 stakeholders Presentation Task-2 Adjusted Roadmap C/B Analysis to Draft Decision stakeholders recommended Adjusted Roadmap Decision Makers Draft Decision Approve the draft Analyzed and metrics Decision considered Target: Launch the Adjusted Roadmap. Time to implement pillars before full market operation milestone Source: Authors Volume 3: Regulatory and Performance Monitoring 267 A draft of the refined roadmap is presented in Annex 1, known as a RACI matrix describes the participation by which retains the same approach of the previous deci- various roles in completing tasks or deliverables for the sions and avoids changes in style or the introduction of implementation of the Smart Grid program. new elements, such as the support Articles of the Law and the technical and economic reasons to introduce the The RACI meanings and roles are as follows; changes to the policy. a. Responsible (R): This is assigned to the The expected milestones in the implementation are individual/s who perform the work to achieve the presented in Figure 118. The success depends on the task. For each initiative there will be at least on commitment of the stakeholders and the possible pres- individual assigned as ‘R’ though others may be sure that can be brought to bear by the government and delegated to assist in the work required. institutions. b. Accountable (A) (also approver or final approv- ing authority): This is assigned to the individual The Refined Decision should also consider the “pillars” in ultimately answerable for the prompt and suc- order to enhance the electrical system for a robust Smart cessful completion of the deliverable or task. Grid implementation as well as the full operation of the The assignee ‘A’ will also nominate the individ- electricity market, a milestone to be achieved in 2016. ual responsible, ‘R’, for the performance of the task/s. The assignee ‘A’ must approve the work Additionally, a Decision for approving the KPIs which that responsible ‘R’ delivers. There must be only will control and monitor the Smart Grid initiatives is also one individual assigned as accountable for each required. It is recommended that the approval of the specified task or deliverable. KPIs is achieved independently from the Decision of the Refined Roadmap so that ERAV will have the flexibility to c. Consulted (C): Those whose opinions are sought, change these values (if required) without having to issue typically subject matter experts, and with whom a new Decision of the Roadmap for each change. there is two-way communication. d. Informed (I): Those who are kept up-to-date on F.6.1 Roles and Responsibilities progress, often only upon completion of the task or deliverable and with whom there is just typi- In order to implement the Refined Roadmap, each insti- cally one-way communication. tution has an important role to ensure the successful implementation of the program. The following matrix The main activities associated with the implementation presents the activities to be performed during the imple- of the refined roadmap are identified and described in mentation process. The responsibility assignment matrix Table 82. TABLE 82: RACI MATRIX FOR THE ROLES AND RESPONSIBILITIES OF THE REFINED ROADMAP Activity NPT NLDC ERAV IE Internally approve the Refined Roadmap R R Present the Final Report to other institutions R I I I Define the priorities for Implementation in the short-term R R A Request approval of the Refined Roadmap to regulator R R A Approve the Refined Roadmap and the Smart Grid initiatives in the short, medium C C R I and long term Based on the recommended KPIs, define the final targets for the KPI for the C C R implementation Include the approved investments in the Master Plan CA CI I R Follow up the approved Smart Grid investments through the KPIs CI CI R Source: Authors 268 Smart Grid to Enhance Power Transmission in Vietnam TABLE 83: RESPONSIBLE FOR DETAILED STUDIES AND IMPLEMENTATION OF THE SMART GRID INITIATIVES Responsible for Responsible for Smart Grid Initiative Detailed Study Implementation Power quality monitoring and Metering Data Acquisition Systems NLDC NPT Dynamic Thermal Circuit Rating NPT NPT Wide Area Monitoring System NLDC NPT Lightning Location System NPT NPT Geographic Information Systems NPT NPT Substation Automation System NPT NPT High Voltage Direct Current technology NPT NPT Static Var Compensator NLDC NPT Fault Locator System NPT NPT On-line Dissolved Gas-in-oil Analysis NPT NPT Source: Authors Complementing the implementation activities of the The KPIs were defined in terms of three different aspects Refined Roadmap, those agencies tasked with the and levels. responsibility to perform detailed studies as well as the implementation of each Smart Grid initiative are also pre- The roles and responsibilities of the involved stakehold- sented in Table 83. ers have been identified and defined. Note that those Smart Grid initiatives connected with the Recommendations for the Roadmap implementation control and monitoring of the Vietnamese Power System have been presented. are assigned to the NLDC for studying and defining the main characteristics for their implementations. These F.7.1.2 Regulatory Analysis activities should be implemented by NPT and be part of the approved CAPEX during the price control review per- The main conclusions are summarized below. formed by ERAV. The renewables integration policy is limited to wind and The recovery mechanism for the Smart Grid initiatives biomass projects and their connection to the nearest are part of the regulatory mechanism detailed in Circular transmission grid point. According to the level of per- No. 14/2010 / TT-BCT issued 15th of May 2010. ceived incentives for investors, the transmission net- work will receive wind and biomass integration, which will have an impact on the reliability of the network as F.7 Conclusions and next steps well as indirectly promoting the reinforcement of the network as well as its enhancement through the use of more advanced technologies like those included in the F.7.1.1 Refined Roadmap and the Key Performance Smart Grid initiatives. indicators The final refined roadmap has been presented and con- The linkage between the renewables policy and the Smart tains the initiatives and their prioritization in the short and Grid applications presented in the current approved Viet- medium term. namese roadmap is not yet fully established. A policy covering both aspects is required in order to support the The metrics to monitor the Smart Grid initiatives from integration of renewables in the transmission network. the technical, economic and regulatory point of view has The benefits from the integration of renewables are been identified, analyzed and presented. important and were quantified at system level in the Cost Benefit analysis performed earlier. Volume 3: Regulatory and Performance Monitoring 269 The Electricity Law has a general framework as does roadmap in order to take advantage of those Decree No. 137/2013/ND-CP for introducing a general applications that ease the integration of renew- framework for international interconnections. Special able sources in to the transmission network. conditions at odds with the ones that apply in general d. The international interconnection policy needs and that might disadvantage other participants in the a greater degree of clarity. This may have some electricity market should be avoided. In this context a significance for the development and deployment clearer policy regarding international interconnections is of some of the Smart Grid initiatives, e.g., HVDC required as this may affect the development and deploy- interconnection, more stringent requirements for ment of Smart Grid initiatives like HVDC as well as lead- online monitoring and security assessment to ing to an increased use of SVC in order to ensure the ensure frequency/voltage problems do not cas- stability of the systems and link. cade from one system to another, etc. A policy that addresses these points may enable the inclu- The mitigations of the KPIs stated in the Smart Grid Road- sion of technologies like HVDC and to increase map are considered insufficient when contrasted with the use of SVC for maintaining the stability of the the quality of service KPIs of other developed countries. systems and links For this reason, the following actions are recommended: e. The Electricity Law does not define penalties or a. Introduce rigorous targets for quality KPIs in the incentives for failing or exceeding the quality of medium and long term in order to reduce the service requirements. The revision of the Grid number and duration of the interruptions. Code is also silent on the issue of penalties for failing to meet minimum standards in the qual- b. Given the geography of Vietnam and its power ity of service. The lack of penalties weakens the system topology, introduce the SAIFI and SAIDI introduction of Smart Grid technologies, which indicators by region (north, south, central), in are being pushed by the industrial user commu- order to better trace the quality and avoid mask- nity who have a poor perception of the quality of ing some indicators for a particular region. service of electricity supplies. c. Introduce penalties for the transmission network f. It is recommended that the Smart Grid policy operator if the regulatory targets for the quality complement Decision No.: 1670QĐ-TTg of indicators are not met. November 2012 with both KPIs and penalties, in order to measure and track the performance The analysis performed in this study has also addressed of Smart Grid initiatives. As mentioned before, many of these topics and is a baseline for improving the the final values of KPIs and penalties should be Smart Grids policy in Vietnam. defined by ERAV based on the proposed values in this report mindful of the overall regulatory The main recommendations are summarized below: framework. a. The system security policy is an implicit part of g. Finally, Circular No. 14/2010 / TT-BCT from 15th the Grid Code and needs to be complemented of May 2010 describes a detailed mechanism with on-line security assessment criteria in order for the recovery of investments in the transmis- to avoid repeating past errors. sion system. The Circular clearly establishes that each year, based on the principle of ensuring full b. The Grid Code should also establish under the cost recovery and retaining permitted profits the same policy, the tools that the System Opera- operator is required to run the transmission grid tor must have in order to evaluate the security according to the quality regulations and to meet and perform on-line monitoring and control of key financial targets for the investment and devel- the voltage/dynamic stability of the Vietnamese opment of the transmission grid. At present no Power System. improvements are recommended for the present c. The renewables policy is generally focused on mechanism. wind and biomass sources, and the criteria, meth- odologies and incentives established are focused Finally some recommendations for the Smart Grid imple- on the planning procedures rather than on fos- mentation were presented; emphasizing the roles played tering and assessing renewable energy develop- by the different participants involved (ERAV, NPT, and ments. It is recommended that the renewables NLDC). The matrix presented the activities to be per- policy complement the developed Smart Grid formed until the implementation of the program. The 270 Smart Grid to Enhance Power Transmission in Vietnam responsibility assignment matrix known as a RACI matrix At the approval level the following steps are recom- described the participation by various agencies in com- mended according to the RACI matrix previously pleting tasks or deliverables for the implementation of presented: the Smart Grid program. a. NPT internally approves the Refined Roadmap; Complementing the implementation activities of the b. NPT presents the Final Report to other stake- Refined Roadmap, those tasked with the responsibility holder agencies; to perform detailed studies and implementation of each Smart Grid initiative were also identified. c. The involved stakeholders define the priorities for the implementation in the short-term; There is a basic legal framework underpinned by the d. NPT presents a request for approval of the Smart Electricity Law, that supports the development of the Grid initiatives to ERAV; proposed Smart Grid initiatives in the transmission sys- tem. It was recommended that a formal Decision with a e. ERAV approves the Smart Grid initiatives in Refined Roadmap be issued. This approach will reduce the short, medium and long term by issuing a the risks associated with the introduction of a new tech- Decision; nology and will do much to smooth the way through the f. ERAV defines the final KPI targets for the Smart multi-layered approvals process. Grid implementation based on the recommended values; A proposed Amendment to the current Smart Grid Deci- sion is presented in ‘ANNEX -1 Proposed Amendment to g. ERAV issue a separate Decision in order to the Decision No.: 1670QĐ-TTg’, which is based on the approve the KPIs; and jurisprudential method for introducing new technologies. h. The Institute of Energy should include the approved Smart Grid applications in the Master The regulatory recovery mechanism of the Smart Grid Plan. initiatives detailed in Circular No. 14/2010 / TT-BCT issued 15th of May 2010 is also confirmed as the prevailing pro- Finally, at the implementation level the following steps cedure until the regulatory approach for governing the are recommended: transmission network changes. a. Conduct trainings sessions on Smart Grid theory Finally, it was recommended that a separate Decision be for the involved stakeholders; issued for the approval of the KPIs to control and monitor the Smart Grid initiatives so that ERAV have the flexibility b. Perform site visits in order to provide practical to change these values (if required) without having to re- experience of the implementation of working issue a Decision of the Roadmap for each change. Smart Grid solutions; c. Perform a complete survey of the historical data, F.7.1.3 Next Steps information and requirements needed for each Smart Grid initiative in order to conduct detailed In general, the next steps in the Smart Grid Development studies; and in Vietnam are divided in two separate levels: d. Collect the surveyed data in one repository for a. Approval level; and different users in order to have single point of ref- erence for future Smart Grid developments. b. Implementation level. e. Conduct detailed studies of those Smart Grid applications identified as a priority. ANNEX 1. Proposed Amendment to the Decision No.: 1670QĐ-TTg Following is a proposed Amendment to the current Deci- - Present a plan to include and operate auto- sion in order to introduce the new initiatives identifies in matic State Estimation algorithms and on-line the study. N-1 Security Assessment procedures on a daily basis. The underlined text corresponds to the new one. - Develop a project for on-line Dynamic Security simulation and integrate it in the daily opera- Article 1. Approve project of Smart grid tional procedures. development in Vietnam is as following - Present a plan to implement secondary Load- contents: Frequency Regulation (Automatic Generation Control). 1. Targets: - Present a plan to perform a detailed survey of a) General target: Develop Smart grid with support of all installed protection systems. high technology in order to improve quality and - Present a plan to double the protections on reliability of power supply; contribute demand most critical lines. side management, encourage to implement energy saving and efficiency; create favorable - Develop an installation strategy of protection conditions for improvement of labor productivity, that will support a consistent and incremental reduction of investment demand on generation improvement of system reliability. and power network; enhance the rational exploita- - Present a plan to either repair or replace tion of energy resources, ensure national energy unsuitable or damaged protection systems. security, contribute to environmental protection and sustainable socio-economic development. c) Specific target: b) Preliminary and urgent initiatives: - Finalize legal framework of power sector to create legal basic to develop Smart grid: These activities should be finalized in 2017 in order Review, adjust, supplement current legal to have a solid base for the Smart Grid development: documents; develop new legal documents on development of renewable energy; develop - Implement local automation strategy in sub- technical standards, rules accordingly. stations with three autotransformers. - Develop IT infrastructure system, communica- - Present a plan to evaluate unsuccessful single tion system and improve monitoring system, pole re-closing in substations and address the automation and control system for power sys- verification of the design of neutral reactance tem, remote metering system: in substations where a high percentage of errors occur. + To 2015: Establish adequate baselines (technical, economic and regulatory) to - Present a plan for short circuit current evalua- address the commencement of the deploy- tion to highlight the critical areas both at pres- ment of Wide Area Measurement System, ent and in the future. Lightning Location System, Power quality - Develop a project for breaker substitutions in monitoring system, Metering Data Acquisi- order to solve the problem of short circuit cur- tion System, Geographic Information Sys- rent exceeding the breakers rated current in tems and Dynamic Thermal Circuit Rating. critical areas. In the meanwhile continue with Substation Automation System implementation at the - Present a plan for the installation of reactors already planned installation pace. between bus bars in those areas known to have high short circuit currents. 271 272 Smart Grid to Enhance Power Transmission in Vietnam + To 2016: Exploit all functions of Energy - Encourage research and manufacturing a Management System (EMS) of SCADA/ number of electronic products on smart grid EMS system at National Load Dispatch in Vietnam in order to meet the demand for Center and regional load dispatch cen- Smart Grid technology. ters. Begin the feasibility study for future - Facilitate customers can directly know and Static Var Compensator. Address the ben- manage specific information on tariff and elec- efits evaluation of Fault Locator System tricity use. initiative. + To 2017: Begin the feasibility study for 2. Smart Grid development roadmap in future High Voltage Direct Current lines, Vietnam both for the interconnection with neigh- bouring countries and for long links con- Approve Smart Grid development roadmap in Vietnam necting the Northern and Southern parts of that was divided into three phases as follow: Vietnam. a) Phase 1 (2016-2020): + To 2022: SCADA/DMS system of Power Corporations; remote metering system - Program of enhancement of efficiency of will be invested adequately to whole larger power system operation: customers. + Complete the SCADA/EMS project for - Improve reliability of power supply: System National Load Dispatch Centre, Regional average interruption frequency index – SAIFI Load Dispatch Centers. Install completely will be reduced 10% and System average the devices to collect operation data from interruption duration index – SAIDI will be substations/power plants connected to reduced 20% after each 5 years period. 110kV grid and above; complete automatic reading system of electronic meter at - Equip automatic and controllable equipments power plants, and delivery points between in order to enhance labor productivity in power power plants and transformer station at sector: 110kV transformers are equipped auto- 500, 220, 110kV. matic and remote controllable equipments in order to reduce staff to 3-5 persons in each + Implement the applications to enhance reli- substation; implement the remote switching ability and to optimize operation of trans- in medium voltage network. mission, distribution grids; reduce losses; especially the applications to protect safety - Enhance ability to forecast demand and develop of 500kV operation such as fault recorder of power supply plan; limit outage or power cut system, detection and protection system caused by lack of generation through mecha- of outage wide-area. Such Smart Grid nism of loading shift in the peak hours or emer- solutions include: Substation Automation gency condition: Decrease 1-2% of peak load System, Wide Area Measurement System, through the application of Advanced Metering Lightning Location System, Power quality Infrastructure (AMI). monitoring system, Metering Data Acquisi- - Implement the technical solutions, manage- tion System, Geographic Information Sys- ment measures in order to reduce power tems and Dynamic Thermal Circuit Rating. losses (technical and non-technical losses) in After the preliminary activities, necessary power system (transmission and distribution) for the feasibility study and benefits evalua- from 9.23% in 2011 to 8% in 2015. tion, the deployment of Static Var Compen- sators and a Fault Locator System has to - Apply Smart Grid technology to stably connect, be performed. Finally address the feasibility operate new and renewable energy; facilitate study for future High Voltage Direct Current efficient exploitation of new and renewable lines. energy sources, encouraging development and increasing density of new and renewable + Check and monitor the implementation of energy in generation; contribute to environ- regulation on mandatory data collection mental protection, national energy security. system in power plants, substations con- nected to 110kV networks and above. Volume 3: Regulatory and Performance Monitoring 273 + Initially equip SCADA/DMS system for + Recommend the financial mechanism to distribution power corporations, provincial develop Smart Grid. power companies. This includes the soft- + Base on researching result and accessing ware, hardware and Communications sys- of efficiency of programs in actual, issue tem, automation and telecontrol system of or review regulatory documents in order to selected 110kV. deploy infrastructure and implement Smart + Training and enhancing the Smart Grid grid applications. implementation capacity of National Power - Development of technical regulations: Research- Transmission Corporation, National Load ing, issuing of technical standards for Smart Dispatch Centre, distribution power corpo- Grid, such as: advanced metering infrastruc- rations, power companies. ture, technical requirements for automation + Complete full integration of Smart Grid system, telecontrol system of transformer applications in daily system operation and stations; SCADA/EMS/DMS system; inte- asset management procedures. grated renewable generation and embedded generation standards; configuration of Smart + Complete the programs, technical assis- grid and related regulations. tance project on load research, demand side response for distribution power corpo- - Communication program for social: rations, power companies. + Preparation and Full dissemination of Com- + Development and implementation of munication program for the Smart Grids advanced operation tools for the integra- for: Institutions, Generation Companies, tion of large amount of non-manageable Power Corporations, Large Customers renewable power in the system (wind, + Preliminary dissemination of the program solar energy…). for residential customers. + Building of High Voltage Direct Current lines b) Phase 2 (2021-2025): according to the results obtained from the feasibility study performed in Phase 1. - Keep doing the Program of enhancement of efficiency of power system operation, focus - Pilot programs: on distribution network; equip IT and commu- + Pilot project for advanced metering infra- nication infrastructure system in distribution structure (AMI) applied to selected big network: customer in Ho Chi Minh City Power Cor- + Complete SCADA/DMS system for the dis- poration in order to implement Demand tribution power corporations; continue to Side Management program. equip the automation equipment for 110kV + Pilot project for integration of renewable substations. generation in Centre Power Corporation: + Implement SCADA/DMS for some pro- apply for small hydro power plants, new vincial power companies that have big and renewable generation. demand, connect to some selected MV - Building of related regulatory framework: substations. + Complete the load research procedures + Continue to build the Smart Grid implemen- tation capacities for the distribution power + Develop the mechanism to encourage cus- corporations and power companies. tomer participating in demand side man- agement program in pilot program in HCMC + Develop test and pilot program on optimal PC. Accessing the program result and com- transmission network operation pleting the encouraging mechanism - Implement Smart grid applications: + Building the legal framework for applying + Dissemination of AMI lesson learnt. Exten- the technical standards, the dispatching sion of AMI system to big customers in regulation for substation automation and all PCs. Implement pilot project allowing telecontrol in power system. customer to trade in on the competitive 274 Smart Grid to Enhance Power Transmission in Vietnam market (wholesale competitive market and + Full dissemination –in stages- of the pro- pilot retail competitive market) at all PCs. gram for residential customers. + Integrate embedded generations, new c) Phase 3 (2026-2030): energy generations, and renewable gen- - Continue to implement equip IT and commu- erations into the network at medium and nication infrastructure system in distribution low voltage. network: + Development of pilot projects for Smart + Deploy the SCADA/DMS system for all Homes. provincial/district power companies to rea- + Creation and implementation of a pilot sonable number of medium-voltage distri- Smart City bution stations. - Building of related regulatory framework: + Extend the advanced energy management and optimal tools in operation from trans- + Research and recommend the authority mission grid to distribution network. to issue the mechanisms: encouraging + Implement AMI system to residential cus- smart grid applications in development tomer; provide customer the opportunities of renewable energy sources; encourag- to trade in on the retail competitive market. ing smart grid applications in zero energy house (non-consumed of energy from out- + Possible investment in “On-line Dissolved side); encouraging smart grid applications Gas-in-oil Analysis” for the prevention of in energy trading between customers and transformers faults, especially on the most power utilities. valuable equipment. + Develop encouraged mechanism for resi- + Continue to encourage development of dential customer to participate the DSM embedded generation. program. - Program of Smart grid applications implemen- - Develop technical regulations: research and tation: Implement the smart grid applications recommend the authority to issue technical that allow electricity demand-supply balancing regulations/standards for energy storage tech- at customer level (Smart Homes). Dissemi- nology, smart appliances used in-house which nate the use of renewable energy widely in can control energy consumption follow supply distribution grid with the time-of-usage elec- condition or tariff changing. tricity price mechanism associated with retail competitive power market operation. - Communication program for social: - Build regulatory framework which allows + Update of Communication program for the deploying smart grid applications based on Smart Grids to include the new fee and tar- existing information technology infrastructure. iffs approach. References [1] Ngo Son Hai, Nguyen The Huu, “Operational Prob- [7] Pham Quang Huy, Overview of Vietnam Power lems and Challenges in Power System of Vietnam” , Market Development, ERAV, March 2014 . National Load Dispatch Centre of Vietnam” [8] Electricity Law 2004. [2] DECISION 1670QĐ-TTg, “APPROVAL OF SMART [9] h t t p : / / b u s i n e s s t i m e s . c o m . v n / GRID DEVELOPMENT PROJECT IN VIETNAM” , blackout-to-hit-firms-hard/ November 2012. [10] Socialist Republic of Viet Nam: Establishing the [3] Mathew J. Morey, Performance Based Regulation Wholesale Electricity Market, Asian Development For Independent Transmission Companies, Har- Bank, December 2014. vard University and Evison Consulting. [11] ERAV, Overview of Vietnam Power Market Devel- [4] Crew and Kleindorfer, 1996, p. 215. opment, March 2014 [5] Tooraj Jamasb,Benchmarking and regulation of [12] http://www.vir.com.vn/blackouts-prompt-call-for- electricity transmission and distribution utilities: powerful-measures.html lessons from international experience, Department of Applied Economics, University of Cambridge and [13] http://www.bloomberg.com/news/2013-12-05/ Michael Pollitt Judge Institute of Management, Uni- vietnam-faces-growing-threat-of-power-blackouts- versity of Cambridge, 2000. southeast-asia.html [6] Vietnamese Grid Code. [14] Decision No. 1208/QD-TTg approving the seventh power development plan for the period 2011 to 2020 with a vision towards 2030. MAPS, FIGURES AND TABLES SOURCES that fiscal targets for investment and development of the transmission grid. (1) ERAV, Power Market developments in Vietnam, October 2010. 5. Article 22 of the Grid Code. (2) IEEE/CIGRE Joint Task Force on Stability Terms and 6. Article 23 of the Grid Code. Definitions, “Definition and Classification of Power 7. Please refer to Task-2 Report. System Stability”, July 2003. 8. Please refer to Task-2 Report. ENDNOTES 9. The only document available and received regarding 1. It is important to maintain a holistic view of the power the regulatory framework is the Electricity Law of 2004 system and to avoid partial analysis that only looks at the and the Grid Code for Generation Competitive Market transmission activity. Draft 4.1. 2. The Technical Analysis was performed in Task-1 Report. 10. According to the Article 66, pint 1, paragraph h) of the Electricity Law. 3. The Cost Benefit Analysis was performed in Task-2 Report. 11. The only document available and received regarding the regulatory framework is the Electricity Law of 2004 4. The Rate of Return on equity for the National Power and the Grid Code for Generation Competitive Market Transmission Corporation (%) is determined to ensure Draft 4.1. 275 This document presents a study on smart grid technology options for Vietnam. With electricity consumption nearly matching generation in recent years and insufficient investment in new power plants, the electricity grid is under constant strain by the growing economy. Realizing the large technical, institutional and financial challenges posed by this expansion level will be a key priority for Vietnam’s grid system operators in the short term. Building on international experiences the report identifies viable smart grid solutions for Vietnam’s transmission network.