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Smart Grid Security

Annex I. General Concepts and Dependencies with ICT

[Deliverable – 2012-04-19]

I Smart Grid Security

Annex I. General concepts and dependencies with ICT

This document is Annex 1 (of 5) to the ENISA study ‘Smart Grid Security: Recommendations for Europe and Member States, June 2012’.

Contributors to this report

ENISA would like to recognise the contribution of the S21sec1 team members that prepared this report in collaboration with and on behalf of ENISA:

Elyoenai Egozcue,

Daniel Herreras Rodríguez,

Jairo Alonso Ortiz,

Victor Fidalgo Villar,

Luis Tarrafeta.

Agreements or Acknowledgements

ENISA would like to acknowledge the contribution of Mr. Wouter Vlegels and Mr. Rafał Leszczyna to this study.

1 S21sec, the contractor of ENISA for this study is an international security services company with offices in several countries.

https://www.enisa.europa.eu/activities/Resilience-and-CIIP/critical-infrastructure-and-services/smart-grids-and-smart-metering/ENISA-smart-grid-security-recommendations

https://www.enisa.europa.eu/activities/Resilience-and-CIIP/critical-infrastructure-and-services/smart-grids-and-smart-metering/ENISA-smart-grid-security-recommendations

II Smart Grid Security


About ENISA

The European Network and Information Security Agency (ENISA) is a centre of network and information security expertise for the EU, its member states, the private sector and Europe’s citizens. ENISA works with these groups to develop advice and recommendations on good practice in information security. It assists EU member states in implementing relevant EU legislation and works to improve the resilience of Europe’s critical information infrastructure and networks. ENISA seeks to enhance existing expertise in EU member states by supporting the development of cross-border communities committed to improving network and information security throughout the EU. More information about ENISA and its work can be found at www.enisa.europa.eu.

Contact details

For contacting ENISA or for general enquiries on CIIP & Resilience, please use the following details:

E-mail: [email protected]

Internet: http://www.enisa.europa.eu

For questions related to ‘’Smart Grid Security: Recommendations for Europe and Member States’’, please use the following details:

E-mail: [email protected]

Legal notice

Notice must be taken that this publication represents the views and interpretations of the authors and editors, unless stated otherwise. This publication should not be construed to be a legal action of ENISA or the ENISA bodies unless adopted pursuant to the ENISA Regulation (EC) No 460/2004 as lastly amended by Regulation (EU) No 580/2011. This publication does not necessarily represent state-of the-art and ENISA may update it from time to time.

Third-party sources are quoted as appropriate. ENISA is not responsible for the content of the external sources including external websites referenced in this publication.

This publication is intended for information purposes only. It must be accessible free of charge. Neither ENISA nor any person acting on its behalf is responsible for the use that might be made of the information contained in this publication.

Reproduction is authorised provided the source is acknowledged.

© European Network and Information Security Agency (ENISA), 2012

http://www.enisa.europa.eu/

mailto:[email protected]

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III Smart Grid Security


Contents

1 Smart grid basic concepts ..................................................................................................... 1

1.1 Definition of the smart grid ............................................................................................ 1

1.2 Objectives of the smart grid ........................................................................................... 2

1.3 Drivers for the adoption of the smart grid ..................................................................... 3

1.3.1 Europe ..................................................................................................................... 4

1.3.2 US ............................................................................................................................ 4

1.3.3 Japan ....................................................................................................................... 5

1.3.4 China ....................................................................................................................... 5

1.3.5 South Korea ............................................................................................................. 5

1.3.6 Brazil ........................................................................................................................ 6

2 The smart grid architecture .................................................................................................. 7

2.1 Quick overview on related standardisation efforts ....................................................... 7

2.2 The smart grid along the electricity value chain ............................................................ 8

2.2.1 Electricity generation in the smart grid .................................................................. 9

2.2.2 Electricity transmission ......................................................................................... 10

2.2.3 Electricity Distribution........................................................................................... 10

2.2.4 Customers ............................................................................................................. 11

2.2.5 Markets ................................................................................................................. 12

3 ICT in the smart grid ............................................................................................................ 13

3.1 IT in the generation domain ......................................................................................... 13

3.2 IT in the operation of transmission networks .............................................................. 14

3.2.1 Substations: types and basic components ............................................................ 14

3.2.2 Automation of electricity transmission ................................................................ 15

3.2.3 Smartening the transmission grid ......................................................................... 16

3.3 IT in the operation of distribution networks ................................................................ 16

3.3.1 Basic aspects of distribution grids......................................................................... 16

3.3.2 Automation of power distribution ........................................................................ 17

3.3.3 Advanced Distribution Automation ...................................................................... 19

IV Smart Grid Security


3.4 IT in Advanced Metering and Energy Management Automation ................................ 20

3.5 Communications networks in the smart grid ............................................................... 22

3.5.1 Communication networks at the customer premises .......................................... 23

3.5.2 Communication networks supporting distribution-related information technologies and applications ............................................................................................ 24

3.5.3 Communication networks supporting transmission-related information technologies and applications ............................................................................................ 25

3.5.4 Common Communication networks supporting transmission and distribution .. 25

3.5.5 Communication networks at the generation domain .......................................... 26

3.5.6 The role of the Internet in the smart grids ........................................................... 26

3.6 Communication technologies ...................................................................................... 27

4 Bibliography ........................................................................................................................ 30

5 Abbreviations ...................................................................................................................... 46

V Smart Grid Security


List of Tables

Table 1 Chief objectives of the smart grid in the EU and in the USA. Sources: EC Task Force for Smart Grids’ Expert Group 1 (5) and US DoE Smart Grid System Report (6) ............................... 3

Table 2 Application level communication protocols and related standards in the smart grid .. 28

Table 3 Communication media and low-level protocols ............................................................ 29

VI Smart Grid Security


List of Figures

Figure 1 Past, present and future of the Smart Grid. The drawing is based on IEA’s Smart Grids Roadmap (4) .................................................................................................................................. 2

Figure 2 Relationship between NIST SP 1108 and IEEE 2030 concepts. The drawing is based on IEEE P2030 standard (14) .............................................................................................................. 8

Figure 3 The smart grid’s power transport domains .................................................................... 9

Figure 4 Substations and customer types in the power grid ...................................................... 14

Figure 5 the power system and its underlying communication infrastructure (based on (14)) 23

1 Smart Grid Security


1 Smart grid basic concepts

1.1 Definition of the smart grid

The European Commission adopted the Communication COM(2011) 202, “Smart Grids: from innovation to deployment” (1) where it defines the smart grid as “an upgraded electricity network to which two-way digital communication between supplier and consumer, intelligent metering and monitoring systems have been added”. Additionally, the European Smart Grid Task Force (2) and The European Smart Grid Technology Platform (Smart Grids ETP) define the smart grids as “electricity networks that can efficiently integrate the behaviour and actions of all users connected to it — generators, consumers and those that do both — in order to ensure an economically efficient, sustainable power system with low losses and high quality and security of supply and safety”.

In the USA, the Office of Electricity Transmission and Distribution, which belongs to the Department of Energy (DoE) defines the grid of the future as one that will incorporate digital technology to improve reliability, security, and efficiency of the electric system through information exchange, distributed generation, and storage sources (3). Moreover, the Department of Energy, describes the smart grid as “a class of technology people are using to bring utility electricity delivery systems into the 21st century, using computer-based remote control and automation. These systems are made possible by two-way communication technology and computer processing [...]”.

From the definitions above, it is clear that from a broad perspective, the smart grid is the term used to refer to the upgraded electricity network of the 21st century, for which information and communication technology is of paramount importance (e.g. computer-based remote control, monitoring and processing; system automation; two-way digital communications between supplier and consumer; intelligent metering; etc.) in order to achieve efficiency, sustainability, quality, reliability, safety and security as well as to manage distributed generation, energy storage, and integrate generators, consumers and prosumers.



Figure 1 Past, present and future of the Smart Grid. The drawing is based on IEA’s Smart Grids

Roadmap (4)

1.2 Objectives of the smart grid

When analyzing the high level objectives of the smart grid, both the EU and the USA (and other countries) mostly coincide. In the table below it is shown a comparison between these two regions. In both cases it is agreed that the smart grid will facilitate greater customer participation, allow for all types and sizes of generation, provide adequate power quality, efficiency, security and reliability, and will create opportunities for new services and market integration. The main difference is that the EU considers a strategic objective the reduction of the environmental impact of the whole electricity supply system. On the other hand, the US stresses the need for optimizing asset utilization and operation efficiency. However, despite the fact that the US does not consider the environmental impact of the electricity supply system as a primary objective, it is understood that this is an underlying goal.

EU USA

Better facilitate the connection and operation of generators of all sizes and technologies.

Accommodate all generation and storage options.

Allow consumers to play a part in optimising the operation of the

Enable informed participation by customers.



Table 1 Chief objectives of the smart grid in the EU and in the USA. Sources: EC Task Force for Smart Grids’ Expert Group 1 (5) and US DoE Smart Grid System Report (6)

Even though the high level objectives of the smart grid are mostly the same in all countries, the drivers for the adoption of the smart grid (see 1.3) can vary. These drivers will determine where the largest investments will focus on, as well as the technologies, system architectures, initiatives and research actions that will be undertaken in each country or region. For instance, in the EU there are many initiatives on microgrids since renewable energy sources (mainly wind-based) are very well adopted among several European countries (e.g. Denmark already receives 40 percent of its electricity from wind (7)). The EU is fostering the use of microgrids as a way to improve the reliability of the network. Microgrids can maintain service by islanding during outages of large systems and at the same time reduces the dependence on large generators and the regional and national grid. On the other hand, the U.S. focuses more on reliability benefits from technology tools for sensors, greater automation, and monitoring (e.g. use of synchrophasors) (8).

1.3 Drivers for the adoption of the smart grid

The main drivers for the adoption of the smart grid can differ from one country or region to another. This is not a minor issue, since the main priorities might be different even though the main objectives might remain the same. Moreover, the starting point of each country might also differ. Some countries might consider their infrastructure reliable already while others will need to heavily invest to improve it. Likewise, the current grid architecture might be different depending on historical, geographical or demographical factors. As a result, the

system.

Provide consumers with greater information and options for how they use their supply.

Significantly reduce the environmental impact of the whole electricity supply system.

N/A

N/A Optimize asset utilization and operating efficiently.

Maintain or even improve the existing high levels of system reliability, quality and security of supply.

Provide the power quality for the range of needs.

Operate resiliently to disturbances, attacks, and natural disasters.

Maintain and improve the existing services efficiently. Enable new products, services, and

markets. Foster market integration towards European integrated market.



implementation paths (e.g. policies or regulatory initiatives, standardisation efforts, technologies, and architectures) might be different resulting in different security challenges, central topic of this study.

In order to better understand where each country will focus its activities (policies, initiatives, regulation efforts, standardisation efforts, etc.) in the following lines we will roughly describe the main drivers for the adoption of the smart grid.

1.3.1 Europe

The EU has established three core policy objectives on Energy which were agreed by the European Council in March 2007 (9): i) increasing the security of supply, ii) ensuring the competiveness of European economies and the availability of affordable energy, and iii) promoting environmental sustainability and combating climate change. Regarding the climate change policy objective, the Europe 2020 growth strategy for the coming decade further establishes three major goals (10): i) renewable sources have to contribute 20% to Europe’s final energy consumption, ii) greenhouse gas emissions have to fall by 20% (or even 30%, if the conditions are right), and iii) energy efficiency gains have to deliver 20% savings in energy consumption.

One of the EU’s measures to reduce greenhouse gas emissions is the massive use of the Electric Vehicle (EV). The EU’s Smart Grid needs to support them, and need to be smart to deliver power at the right moment and at the same time maintaining the reliability of the network. For instance, cars could be charged during the night or during the day while they are parked in the parking lots.

Reliability in the EU’s grid is of high importance for Telecommunication infrastructures. EU’s telecommunications operators are used to a reliable grid and, as a result, many telecommunication infrastructure operators do not have back-up generators. Reliability metrics varies among different Member States but most of EU’s countries have an average disconnection time under 100 minutes per year and customer. However, there are other EU Member States that do not provide such good figures (e.g. Poland average disconnection time in 2007 was around 550 minutes/year/customer).

1.3.2 US

Title XIII of the Energy Independence Security Act of 2007 (EISA) (11) is a statement of policy on modernization of the US electricity grid. This Act states that the “US policy aims to support the modernisation of the electricity transmission and distribution system to maintain a reliable and secure electricity infrastructure that can meet future demand growth”.

The US grid is plagued by ever more and ever worse blackouts over the past 25 years. The US grid spans vast geographical areas, and the long distances between the power plants and the final customers render the infrastructure unstable and prone to cascading effects. The average disruption time per customer is 214 minutes (excluding hurricanes and strong storms) in the Northeast coast, while Japan averages 4 minutes of interrupted service each year (12).



There is a need for TSOs and DSOs to understand faster how many outages are there, what are the areas affected, how many customers are affected, which customers reconnect first which last. DSO’s also expect from the Smart Grid to balance and steer power from local generation plans in order to supply minimum energy to local towns and communities. Moreover, the US’s transmission grid systems are overloaded and this has resulted in many brown-outs lately. Examples like California’s, Texas, and other incidents back up this idea.

In addition to improving the reliability of the grid, the US – very much like in the EU – also aims to integrate all sources of energy, including renewable into the grid (solar energy, wind power, nuclear, etc.)

A major concern in the US is that there are over 3600 utilities (power companies), and each state together with 3 territorial Public Utility Commissions are in charge of their regulation. This could lead to multiple different paths for smart grid implementation, which means that there might appear a collection of solutions that do not interoperate, limiting their value and the opportunity for nation-wide innovation. As a result, the US entrusted the National Institute of Standards and Technology (NIST) “to develop a framework of standards to reduce the implementation paths to a manageable number, increasing market sizes, stimulating innovation, and speeding deployment by lowering prices and increasing reuse” (11).

1.3.3 Japan

Japan’s electricity grid is considered to be highly reliable. For this reason more efforts will be made to accommodate renewable energy sources and to create new infrastructures, standards and services for the Electric Vehicle (EV).

Additionally, Japan has planned reducing CO2 emissions by 25% compared to the level in 1990 (5). To this respect, the administration will be supporting economically the introduction of the next-generation power distribution grid.

1.3.4 China

China’s demand for Energy is rising very quickly. In order to keep the pace China will highly invest on increasing capacity, reliability, efficiency and the integration of renewable sources.

A secondary objective is the reduction of energy consumption per unit of GDP by a cumulative 20% by 2010 (5). With China’s GDP growing at two digits rate under normal circumstances, this objective seems less ambitious when compared with other regions (e.g. Europe)

1.3.5 South Korea

South Korea aims at building for 2030 the world’s first nationwide smart grid system. They intend to increase the use of green energy in order to reduce greenhouse emissions, which include not only CO2, but also CH4 (methane), N20 (nitrous oxide), and fluorinated gases (5). Another main objective is efficiency by lowering the peak load for electric power and reducing the overall energy use.



1.3.6 Brazil

Brazil, as China, is currently undergoing a great change in its power grid. Only between 2007 and 2017 it is expected a 60% growth with 16-34% increase in renewable from hydro, biomass and wind (12). However, the current grid is aging and it is a one-way power flow.



2 The smart grid architecture

The adoption of smart grids will dramatically change the grid as we know it today. Traditional energy services and markets will also undergo a significant transformation. To this regard, it is envisioned that customers will have a much more active role; they will be efficient energy consumers and electricity producers at the same time.

2.1 Quick overview on related standardisation efforts

Even though the objectives of the smart grid are well defined, there is no clear reference architecture. This is changing however, and standardisation efforts are already in place trying to fill this gap.

The US National Institute of Standards and Technology (NIST) presented in 2010, the NIST SP 1108 (13), which include a high-level framework for the smart grid and defines seven important domains: Bulk Generation, Transmission, Distribution, Customers, Operations, Markets and Service Providers. It helps stakeholders understand the building blocks of an end-to-end smart grid system, from Generation to (and from) Customers. Moreover, it shows all the communications and energy/electricity flows connecting each domain and how they are interrelated. Additionally, each individual domain is further analysed and the most relevant smart grid elements and interconnections (e.g. energy/electricity paths and two-way digital communications) are identified.

NIST is assigned the primary responsibility of coordinating the development of a framework that includes protocols and model standards for the smart grid. IEEE supports EISA, the NIST framework coordination effort. As a result, the IEEE started the IEEE P2030 project which has recently delivered the IEEE 2030-2011 standard. This guide views the smart grid as a “large, complex system of systems and provides guidance to navigate the numerous smart grid design pathways throughout the EPS, loads, and end-user applications” (14).

This guide expands each domain defined in the NIST conceptual reference architecture into three smart grid foundational layers: i) the Power and Energy Layer, ii) the Communication Layer and iii) the IT/Computer Layer. The IEEE considers that layers (ii) and (iii) are the enabling infrastructure of the Power and Energy Layer and which make the grid "smarter”. For each one of these foundational layers, this guide presents a reference model which is based on multiple use case scenarios. For instance, the Communication layer includes the identification of the interfaces between systems, data-flows, potential communication technologies and protocols, security objectives, etc. This standard considers security and privacy as a foundational principle, and makes use of the NISTIR 7628 as a reference for this purpose. As an example, it is worth noting that each type of data flow identified is assigned a security category which consists of an impact level for each of the three security objectives of data confidentiality, data integrity, and data availability.



Figure 2 Relationship between NIST SP 1108 and IEEE 2030 concepts. The drawing is based on

IEEE P2030 standard (14)

On the other hand, the EU is following a similar approach for the European Smart Grid. The Commission issued mandate M490 (15) to European Standardisation Organisations (ESOs) (i.e. CEN, CENELEC and ETSI) whereby they are requested to develop a reference framework on smart grids. The expected framework will include a smart grid reference technical architecture and a set of consistent standards which will support the information exchange (communication protocols and data models) among other objectives. The first results are expected by the end of 2012.

2.2 The smart grid along the electricity value chain

The smart grid is a concept that spans all along the electricity value chain. It encompasses the power generation domain, the electricity transmission and distribution systems and associated operations, the metering and billing processes and other end-user services, and even power markets. Figure 3 provides an overview of these concepts.

All of these domains (generation, transmission, distribution, etc.) already existed before the concept of smart grid was envisioned. However, it is also acknowledged that a smarter grid is necessary to deal with today’s energy challenges.

In the following lines an overview of the different domains affected by the smart grid is presented, by comparing the current situation of all to how they will look like in the coming years.



Figure 3 The smart grid’s power transport domains

2.2.1 Electricity generation in the smart grid

The first years of the twenty-first century have seen renewed emphasis on new and renewable sources of electricity. These sources of energy are being deployed massively and will have to be accommodated efficiently in today’s electric grid, complementing other energy sources such as the old – and decreasing – combustion-based technologies, nuclear energy, etc.

Smart grids will integrate traditional, renewable energy sources as well as the concept of distributed generation. These sources will feed different parts of the electricity super-system, including: i) bulk generators connected to the transmission levels, such as nuclear power plants; ii) medium scale generators at the distribution level, such as small-scale combined heat and power or wind farms; and iii) small scale on commercial and residential buildings, such as solar panels and small wind mills.

Bulk generation plants generate electricity from renewable and non-renewable energy sources in bulk quantities. These sources can also be classified as renewable, variable sources, such as solar and wind; renewable, non-variable, such as hydro, biomass, geothermal and pump storage; or non-renewable, non-variable, such as nuclear, coal and gas (16). Bulk generation plants, are large centralized facilities that have excellent economies of scale. However, electricity has to travel long distances to reach customers and as a result a good amount of energy is lost.

In contrast to bulk generation, the smart grid will also accommodate the concept of distributed or dispersed generation, where many energy sources of small size – called Distributed Energy Resources (DER) – will be dispersed along the transmission, distribution and customer domains. As it is stated in (17), “a DER may be owned by either a consumer or supplier of electricity and can operate either independently or interconnected with the grid”. In many cases, distributed generation implies (but it is not mandatory – e.g. peaking generation units connected to the transmission system) that electricity is generated very close to where it is used, which reduces the amount of energy lost in transmission and the size and number of power lines that must be constructed. Some examples of distributed energy resources include: solar panels on the roofs of building, small wind turbines, fuel cells, and



distributed cogeneration sources. Moreover, a source of potential DER in the future will be the electrical vehicle (17). Smart grids will support greater deployment of variable generation technologies by providing operators with real-time system information that enables them to manage generation, demand and power quality.

2.2.2 Electricity transmission

Transmission is the bulk transfer of electrical power from generation (and storage) sources to the distribution grid through multiple substations which are typically operated by Transmission System Operators (TSO). The main goal of a TSO is to maintain stability on the electric grid by balancing generation (supply) with load (demand) across the transmission network (13).

In today’s electrical grids, the generation, transmission and sub-transmission segments are performing at a high level and are equipped with automation systems. Even though this will be further explained in future sections, this has been done by installing Remote Terminal Units (RTUs) and other control devices in substations and generation plants, connected to a Distributed Control System or to a centralising SCADA/EMS system.

Companies around the world are already investing in making the transmission network smarter, with renewed ICT for enhanced control and monitoring. According to the IEA Technology Roadmap on Smart Grids (18) “many transmission systems already use some smart grid technologies and are operating robustly, allowing for adequate competition among generators and therefore ensuring appropriate electricity prices. Other transmission systems are plagued by congestion and concerns over ageing infrastructure. […] New transmission capacity and interconnections with other electricity systems are also needed”. The smart grid will bring a whole range of new specific applications and technologies to improve the transmission system. Some examples are the High-Voltage Direct Current (HVDC), Phasor Measurement Units (PMU), Dynamic Line Rating and Wide Area Measurement System (WAMS).

2.2.3 Electricity Distribution

An electricity distribution network carries electricity arriving from the transmission system, as well as from some generators connected to the distribution network, to industrial, commercial and domestic users. The distribution grid is the electrical interconnection between the transmission domain, the customer domain and the metering points for consumption, distributed storage, and distributed generation (13). The electricity distribution systems are normally operated by Distribution System Operators (DSOs). Furthermore, the traditional main goal of a DSO is not only to operate, but also to maintain and develop an efficient electricity distribution system.

Even though this will be further explained in the following sections, historically, distribution systems have included little telemetry, and almost all communications within the domain were performed by humans. It is considered that “the primary installed sensor base in the distribution domain is the customer with a telephone, whose call initiates the dispatch of a



field crew to restore power”, (13). It was common that distribution substations were rarely connected to a central SCADA system, and even sometimes they were not automated at all. Electrical substations required manual switching or adjustment of equipment, and manual collection of data for load, energy consumption, and abnormal events. In contrast, as already mentioned, TSOs have had extensive control over transmission-level equipment which is now being enhanced with a smarter transmission grid. Nevertheless, control over distribution-level equipment is increasing via distribution automation. However, with the advent of the smart grid, distribution systems are facing a paradigm shift. As it is acknowledged by industry major players (19) “distribution networks are under high pressure to meet requirements for converting their conventional static grids into modern and dynamic smart grids. In particular, the increasing occurrence of decentralized generation (DER) is influencing this trend, as well as the need to improve the quality and reliability in MV and LV networks”. Due to this paradigm shift, there are new requirements on the automation, monitoring control and protection of distribution substations and transformer stations/centres. A more advanced automation is expected at the distribution grid with the upcoming smart grid. Literature refers to this “extra” automation as smart distribution system or Advanced Distribution Automation (ADA). The goal of Advanced Distribution Automation is the real-time adjustment of the distribution system to changing loads, generation, and failure conditions, usually without operator intervention in order to dramatically improve system reliability, power quality, and efficiency. In order to achieve this, substation and feeder automation and control will play a central role, and will allow DSO’s to make the most of Distributed Energy Resources (DER), Advanced Metering Infrastructure (AMI) and Demand-Response strategies, making these three new concepts an essential part of the toolbox of ADA (20). All these new concepts will be explained in detail in the following sections.

2.2.4 Customers The smart grid is a compilation of concepts, technologies, and operating practices intended to bring the electric grid into the 21st century. However, the smart grid could not be understood without the increasing automation of energy management at households, buildings and industry. This is one of the reasons why the frontier between the smart grid, and the smart cities, smart industry, smart buildings and smart houses is blurry.

Once the electricity reaches the client side, the electricity is consumed. In order to gather the necessary consumption readings for billing, DSO’s personnel traditionally made – and still make – periodic roundtrips to each physical location to manually read meters. The evolution towards smart grids will allow DSOs for smart billing, a solution for dynamic pricing and enhanced customer relationship management. According to the IEA Technology Roadmap (18), “smart grids will enable increased interaction between DSOs and customer through the provision of real-time energy usage information and pricing. [...] Moreover, Market unbundling has changed the ownership and operating arrangements of distribution networks and, in many countries, the role of the distribution system operator (DSO). In some countries, an electricity retailer or energy service provider entity is placed between the customer and the DSO”. The end-user, but also the DSO will benefit from this change.



These new electricity retailers or energy service providers are envisioned to provide a whole new range of added-value services, such as supporting the Electric Vehicle (EV), integrated energy management services, a more efficient electricity consumption or integrated home automation, real-time power quality monitoring, premium power options, etc. The use of batteries or local electricity generation technologies mainly based on renewable sources will be also a main topic, as already described in previous sections. Smartening the customer premises will be based on ICT technology that will provide grid operators with increased and better informed control over grid operations. This new source of information and control capabilities will allow grid operators to better manage demand, for instance by allowing islanding sections of the grid when an outage occurs, or signalling real-time tariffs to reduce consumption rates.

2.2.5 Markets

The electricity market includes all those operations related to the purchase and sale of power energy. It encompasses stakeholders such as power suppliers, traders, balance responsible parties, settlement and power exchange agents, etc.

The Markets domain will communicate with the Distribution domain in ways that will affect localized consumption and generation. This will turn Markets to be more dynamic. To this regard, the innovations that bring the smart grid are(21): extending price and distributed energy resources (DER) signals to each of the Customer sub-domains; making more simple market rules; managing the growth (and regulation) of retailing and wholesaling of energy; and evolving communication mechanisms for prices and energy characteristics between and throughout the Markets and Customer.

The liberalisation of the electricity sector, together with the smartening of the distribution grid and customer households and industry, will also allow Markets to become more flexible than they are today. Customers are envisioned to have more options, such as being able to choose for the best power supplier. Besides, markets will play an important role, by providing incentives, with last minute energy offers when in a sudden wind allows for renewable generation to contribute to the grid. Besides, situations such as “if you comply with your load forecast you get good tariffs” will be generalised.



3 ICT in the smart grid

Robust, open and secure Information and Communication Technologies (ICT) are at the core of a successful smart grid implementation. As explained in the previous chapter, all processes across the whole value chain (i.e. energy generation, transmission, distribution, consumption, marketing, retailing, etc.) are heavily based on ICT infrastructures.

Thanks to ICT, the grid of the future will become smarter so as to improve reliability, security, and efficiency of the electric system through information exchange, distributed generation, storage sources, and the active participation of the end consumer. The development of smart grids exemplifies the increasing dependency of European economy and society on Information and Communication Technologies.

In the following lines the dependence of the current and future smart grids of different Information and Communication Technologies will be explained. Firstly, an introduction on how the grid is currently operated will be presented. Then this explanation will be followed by the description of how new technologies and applications will enhance the current automation of the grid operations. Finally, this chapter will provide an overview of the underlying communications infrastructure supporting these existing and new applications.

3.1 IT in the generation domain

Bulk generation and DER operations are heavily automated by Industrial Control Systems (ICS), including mainly PLCs and DCS and other controllers, but also SCADA systems in certain cases. These systems also help human operators to start and stop the generators depending on the need. They play an important role in synchronizing and adjusting the voltage level with regards to the power grid to which they are connected.

In order to address the peculiarities of the integration of renewable energies in the power grid, different approaches are being followed. For instance, in 2006 Spain established a Control Centre of Renewable Energies (CECRE), a pioneering initiative set up by Red Eléctrica, the national TSO. This centre is in charge for controlling and managing the electricity generation obtained from renewable energy producers, primarily wind farms, making it possible to integrate the maximum production of renewable energy into the electricity system whilst maintaining the levels of quality and guaranteeing the security of supply.

According to (22), by means of 23 control centres belonging to several generation companies, which act as interlocutors, “CECRE receives, every 12 seconds, real time information about each facility regarding the status of the grid connection, production and voltage at the connection point. This data is used by a sophisticated tool which makes it possible to verify whether the total generation obtained from renewable energies can be integrated at any moment into the electricity system without affecting the security of supply”.



3.2 IT in the operation of transmission networks

3.2.1 Substations: types and basic components

As it has already advanced in the previous sections, the basic elements of electricity transmission are power lines, transmission towers, and sub-stations. Transmission substations connect two or more power transmission lines. Normally transmission substations include step-up and step-down substations. TSOs operate step-up generation substations which are normally located close to a power plant and which use transformers to raise the voltage level before delivering it to the transmission network. On the other hand, TSOs also operate step-down transmission substations which use transformers as well but in this case to reduce the voltage level between the transmission and sub-transmission levels. High voltage is used in the transmission network to reduce propagation power losses due to the Joule effect. The last substation type operated by TSOs includes those substations where all transmission lines have the same voltage level. This is the simplest substation type, where high-voltage switches allow interconnecting two or more electric circuits, improving the transmission system reliability by creating nodes in meshed topologies. They also facilitate lines to be connected or isolated for fault clearance or maintenance. Likewise, step-up and step-down substations might also include switching gear for this same purpose.

Figure 4 Substations and customer types in the power grid



Substations might include switching, protection and control equipment as well as the aforementioned transformers. Substation switching consists of connecting and disconnecting transmission lines or other components to and from the system. As already mentioned, switching equipment allows improving the transmission system reliability by creating nodes in meshed topologies. Moreover, they are of key importance for maintenance purposes. For instance, isolator switches (also known as disconnectors) are used to make sure that an electrical circuit can be completely de-energised for service or maintenance purposes like adding or removing a transmission line or a transformer. Switching gear is also an important component for the protection of the transmission system, particularly high-voltage circuit breakers. Circuit breakers are automatically operated electrical switches designed to protect an electrical circuit from damage caused by overload or short-circuit. When a fault develops in a transmission line or any other component – due to a lightning that hits a line or a transmission tower which is blown down by strong wind – the substation has to isolate the faulted portion of the system in order to: avoid the whole system destabilization, or the burning of the line/the blowing up of the transformer. Breakers may be operated by power system protection relays2, or through a manual command from power system operators in the TSO’s control centre.

3.2.2 Automation of electricity transmission

The automation of the transmission power grid requires the use of Supervisory Control and Data Acquisition (SCADA) systems for the local control of each substation, as well as for the management of the entire network. Substations include a local control room where a Human Machine Interface (HMI) and Remote Terminal Unit (RTU) computer provides substation local control and supervision to local operators. Furthermore, the whole transmission network is typically monitored and controlled through a SCADA system which remotely interacts with these local control systems at each substation. Supervisory Control and Data Acquisition systems (SCADA) are used for power system switching. SCADA systems in charge of monitoring and control of the whole transmission, in combination with the ancillary applications provided by the Energy Management System (EMS) system, analyze and operate the transmission power system reliably and efficiently (23). From a central control centre room, operators are able to supervise network topology, connectivity and loading conditions, including circuit breaker and switch states, and control equipment status. The SCADA/EMS monitors the open/closed status of all circuit breakers, to create bus/branch topology configurations of the power system, allowing for optimal power flow calculation, state estimation, contingency analysis, outage scheduling, voltage or stability analysis, alarm processing, etc. Moreover, the SCADA/EMS systems also monitor substation metering technology, to retrieve data on line current and voltage levels at substations.

2 Protective or protection relays are substation devices that allow to detect faults (e.g. over-current, over-voltage, reverse

power flow, or over- and under- frequency) on the system and identify the appropriate breakers needed to be open in order to isolate the faults and enable the rest of the system to function normally. They can be either electromechanical or the more modern microprocessor-based digital instruments.



3.2.3 Smartening the transmission grid

As already mentioned in the previous chapters, the smart grid will bring a whole range of new specific applications and technologies to improve the transmission system. The most relevant examples are the High-Voltage Direct Current (HVDC), Phasor Measurement Units (PMU), Dynamic Line Rating and Wide Area Measurement System (WAMS).

In the following lines we will briefly explain each one of these applications and technologies:

HVDC transmission systems use direct current for the bulk transmission of electrical power, in contrast with the more common alternating current systems. For long-distance transmission, HVDC systems may be less expensive and suffer lower electrical losses.

Dynamic Line Rating (DLR) uses sensors to identify the current carrying capability of a section of network in real time to optimise utilisation of existing transmission assets, without the risk of causing overloads (18).

Phasor Measurement Units (PMUs) are devices that provide high quality measurements of bus angles and frequencies using a common time source for synchronisation (i.e. GPS radio clock) (24). PMUs might be autonomous systems or part of a protective relay or other device in a substation. They increase the reliability of the power grid by detecting faults early, increasing the power quality, enabling load shedding and other load control techniques, etc. PMUs are considered the initial data source for Wide Area Monitoring and control (WAMS) applications, essential in regional transmission grids (and also in wide are super grids and local distribution grids).

WAMS evolved as an advanced measurement technology to collect information not available from contemporary supervisory control and data acquisition (SCADA) technology (24). WAMS technologies, as SCADA systems, acquire field data and process them to extract value. Data acquisition is accomplished with a new generation of data recording hardware (e.g. PMU) that produces high quality and high volume recordings that are virtually continuous. Measurements are synchronised against a GPS, and are readily merged to form integrated views of the behaviour of power transmission systems. Furthermore, it is envisioned that WAMS can be included as an ancillary application of the SCADA/EMS system, sometimes referred to as the WAMS server.

3.3 IT in the operation of distribution networks

3.3.1 Basic aspects of distribution grids

The elements that compose the electricity distribution are middle/low voltage lines or feeders and step-down distribution substations and transformer stations/centres3 which respectively

3 In literature, transformer stations/centres are sometimes named distribution substations, not distinguishing from what we

call distribution substations in this document.



convert high voltage to medium voltage or medium voltage to low voltage. The input for a distribution substation is typically two transmission or sub-transmission lines and the output is a number of feeders. The feeders run along streets overhead (or underground, in some cases) and normally4 power the distribution transformers (i.e. at transformer stations or centres) at or near the customer premises (see Figure 4). Transformer stations are then responsible for delivering electricity to the end-user. Distribution substations, in the same way as transmission substations, might include switching, protection and control equipment as well as voltage transformers. These substations isolate faults in either the transmission or distribution systems. In downtown areas of large cities it is easy to find complicated distribution substations which directly feed a large number of low voltage customers. They make use of high-voltage switching, and switching and backup systems on the low-voltage side. On the other hand, transformer centres5, which feed a much smaller number of clients, simply have an isolator switch (disconnector), one transformer, and minimal facilities on the low-voltage side.

Distribution systems normally present radial or open/closed loop6 topological configurations, in contrast with the meshed configurations of transmission systems.

3.3.2 Automation of power distribution

As already mentioned in previous sections, in today’s electrical grids, the generation, transmission and sub-transmission segments are performing at a high level and are equipped with substation automation systems. This is done by the installation of Remote Terminal Units (RTUs) connected to a central SCADA/EMS system. On the other hand, it was common that distribution substations were rarely connected to a central SCADA system, and even sometimes they were not automated at all. As it was mentioned earlier, electrical substations required manual switching or adjustment of equipment, and manual collection of data for load, energy consumption, and abnormal events. However, distribution systems are facing a paradigm shift nowadays. “Distribution networks are under high pressure to meet requirements for converting their conventional static grids into modern and dynamic smart grids. In particular, the increasing occurrence of decentralized generation (DER) is influencing this trend, as well as the need to improve the quality and reliability in MV and LV networks”, (19). Due to this paradigm shift, there are new requirements on the automation, monitoring control and protection of distribution substations and transformer stations/centres.

Nowadays, the most common approach on distribution automation is to focus on feeder automation. Feeder automation aims at four main goals (25): automatic fault detection on

4 It is possible to find distribution substations which deliver electricity right to final customers. This usually happens in

downtown areas of large cities.

5 In the US, where the number of households per square meter is much lower than in Europe, it is quite normal to find that the

transformer stations/centres are replaced by simple transformers at the electric pole which only feed one or two residential customers.

6 Closed-loop configurations are also called ring topologies. In such topologies as well as in open-loop topologies, each

transformer stations/centre can be fed by two electrical paths, improving service reliability and simplifying maintenance tasks.



feeders, fault isolation and service restoration; scheduled feeder section outage for maintenance; main transformer and feeder load transferring and balancing; and main transformer and feeder phase load balancing. To achieve these objectives, RTUs and sensors are distributed all along the distribution grid at the distribution substations and transformer centres. By monitoring digital signal status and thanks to distributed control algorithms, faults can be confined and alarms can be triggered in case of short-circuits, undercurrents and under-voltage contingencies (26). This is sometimes referred as Fault Detection, Isolation and Restoration (FDIR). The monitored signals normally include voltage, currents, instant power/load and losses at each transformer centre. These signals could also be brought to a local SCADA system at the head distribution substation or even directly at the distribution grid’s central SCADA/DMS system for monitoring the whole distribution system status. A Distribution Management System (DMS) is a collection of ancillary applications that, in combination with the central SCADA system, monitor and control the entire distribution network efficiently and reliably. DMSs act as a decision support system to assist the control room and field operating personnel improving the reliability and quality of service in terms of reducing outages, minimizing outage time, maintaining acceptable frequency and voltage levels, etc. (27). Moreover, it is considered that a DMS improves classical Outage Management Systems7 (OMS) by automating service restoration sequences and providing an end to end, integrated view of the entire distribution system status on a single console at the control centre.

In addition to RTUs and SCADA/DMS monitoring and control systems, reclosers are an essential element for prompt and efficient service restoration. Reclosers or auto-reclosers are “circuit breakers equipped with a mechanism that can automatically close the breaker after it has been opened due to a fault”, (28). They are meant to detect and interrupt momentary faults and automatically restore service, since many short-circuits tend to clear themselves. This could be the case of a tree branch falling on a feeder resulting in briefly short-circuiting two phases cables or phase and ground cables. In such a case, a recloser could trigger two or three “fast” reclose operations until the short-circuit condition disappears and service can be restored. Reclosers’ controls may range from the original electromechanical systems to digital electronics with metering and SCADA functions.

In addition to feeder automation, in the last years utilities have also started to collect data from protection relays at distribution substations where numerical relays were installed. These data is brought to the central SCADA/DMS system for visualization and remote control (25). However, levels of automation vary in different countries depending on the strategies of the local DSOs. Likewise, the level of automation and functionality for distribution substations

7 An Outage Management Systems (OMS) is a computer system which makes use of other systems like Customer Information

System (CIS), Geographical Information System (GIS) and Interactive Voice Response System (IVRS) to assist in restoration of power. An outage management system has a detailed network model of the distribution system developed through its GIS. By combining the locations of outage calls from customers, a rule engine is used to predict the locations of outages. Based on this, restoration activities are charted out and the crew is dispatched for the same. (61) (27).



and transformer centres could differ among centres in the same grid or feeder because of different equipment in place or communication infrastructure availability.

3.3.3 Advanced Distribution Automation

As it is clear from the above description, distribution automation provides DSOs with an increasing control over distribution-level equipment. However, a more advanced automation is expected at the distribution grid with the upcoming smart grid. Literature refers to this “extra” automation as smart distribution system or Advanced Distribution Automation (ADA). The goal of Advanced Distribution Automation is the real-time adjustment of the distribution system to changing loads, generation, and failure conditions, usually without operator intervention in order to dramatically improve system reliability, power quality, and efficiency. In order to achieve this, substation and feeder automation and control will play a central role, and will allow DSO’s to make the most of Distributed Energy Resources (DER), Advanced Metering Infrastructure (AMI) and Demand-Response strategies, making these three new concepts an essential part of the toolbox of ADA (20). As it is stated in (17), “traditional distribution automation has been principally concerned with automated control of basic distribution circuit switching functions. ADA is concerned with complete automation of all the controllable equipment and functions in the distribution system to improve strategic operation of the system”.

In order to achieve the goals of ADA new applications and technology are expected to be developed. Applications such as Fault Detection Isolation and Restoration (FDIR), Topology Processor (TP), Distribution Power Flow (DPF), Integrated Voltage/Var Control (IVVC), Optimal Feeder Configuration (OFC), Distribution Contingency Analysis (DCA), Distribution State Estimation (DSE), Distribution Load Forecasting and Estimation (DLF/DLE), etc. will be part of the revolution of distribution automation towards ADA. Intelligent Electronic Devices (IED)8 are key enablers of these applications. Being distributed all along the distribution system, including substations and feeders, IEDs will receive and send data from/to electronic multifunction meters, digital relays, controllers, etc. (17). An example of an IED could be next-generation transformers with an interface providing communication about load, temperature, voltage, etc. IEDs will need to interact and cooperate with RTUs, SCADAs and distributed control systems to add intelligence to the distribution system.

We already discussed the current status of Fault Detection Isolation and Restoration (FDIR) in distribution systems. Probably this feature is more advanced than any other in today’s distribution automation. However, ADA will bring new sophisticated algorithms providing more intelligence and coordination at the central SCADA/DMS systems as well as distributed field control capabilities, aiming at reducing restoration time in what is called to be the self-healing capacity of the grid. An advanced FDIR system will be able to dynamically react to continuously define the most appropriate settings of reclosers, sectionalizers/isolator

8 IEDs are any device incorporating one or more processors with the capability to receive or send data/control from or to an

external source/sensors.



switches and other intelligent relays taking advantage of DER applications or demand-response strategies, and considering system topology changes, or changing load characteristics (17).

In addition to aiding in outage recovery, ADA, and specifically the close control and automation of DER, could be useful for grid reliability and power quality. Let’s imagine a situation where heavy load conditions threaten the stability of the whole distribution system. By intentionally islanding parts of the system (e.g. single house up to a small city) the resulting microgrid might operate independently of the bulk generation with limited or even with a full service level by taking advantage of its own DER resources.

Based on the previous paragraphs the reader should have already noticed that smartening the distribution networks requires considerably more effort than smartening transmission networks. Since distribution networks have many more nodes to be instrumented and managed, ADA will impose much higher ICT requirements. Moreover, distribution systems connect to nearly all electricity customers (excluding large industrial customers connected to the transmission system), as well as distributed generation, variable/dispatchable resources and new loads such as electric vehicles. Therefore, smart grid technology must be strategically deployed in order to manage this complexity (18).

The Advanced Metering Infrastructure (AMI), which is already being deployed by many DSOs will connect smart homes, industries and entire buildings with the utility. It is worth highlighting the importance of AMI for ADA. In addition to its conventional roles in accounting and customer billing, AMI will play a major role in smartening the distribution network. The AMI data from individual customers, including the historical load profiles as well as real time information (e.g. consumption patterns), can also be used to enhance the distribution system operation and management, including for instance load forecasting and estimation in DLF/DLE applications (20). Furthermore, AMI will play a central role in Demand-Response (DR) by extending control systems to smart buildings and smart homes. The current power grid is designed to have generation sources respond on-demand to user needs by incorporating as much power to the network as estimated by load forecastings. However it is envisioned that ADA can allow the DSO to raise the thermostats of houses to “temporarily decrease electrical demand from a large number of customers without significantly affecting their comfort”. Such customers are usually compensated for being enrolled in a load reduction program which allows the DSO to be “intrusive” in their lives. Likewise, it would also be possible for DSOs to send homes, businesses, and even electric vehicles Real-Time Pricing (RTP) signals so that they can dynamically adjust their energy consumption patterns as a way to minimize costs and at the same time preserve autonomy and mitigate privacy issues (29). This will allow customers to shift to a 24/7 based demand response paradigm where the customer sees incentives for controlling load continuously.

3.4 IT in Advanced Metering and Energy Management Automation

As already mentioned in this document, in order to gather the necessary consumption readings for billing, DSO’s personnel traditionally made – and still make – periodic roundtrips



to each physical location to manually read meters. The evolution towards smart grids, and specifically thanks to the Advanced Metering Infrastructures (AMI) and the introduction of smart meters in households, buildings and industry will allow DSOs to get these readings remotely and in an automated way.

The AMI infrastructure provides a two-way communication infrastructure between customers and utilities (i.e. DSOs) and it is one of the main ICT components to smarten the power grid. Such an infrastructure heavily depends on the installation of automated meter reading (AMR) devices, also simply known as smart meters. These devices, which basic objective is measuring energy consumption, as their traditional analog counterparts, are also able to perform operations such as:

Measuring power usage in real-time – or at least, quite often –, recording it, and sending these registers to the DSO or other third party providing energy services.

Monitoring and informing the DSO, the customer and third parties about power quality.

Track customer usage parameters, such as total energy consumption, and keep a historical record.

Remotely connect and disconnect customers from the power grid.

Send out alarms to the DSO in case of technical issues such as component failures or loss of power notifications.

React to real-time pricing signals received from the DSO or energy retailer.

Energy prepayment.

Remotely receive and install firmware upgrades so as to incorporate new functionality.

Anti-tampering and fraud detection.

Remotely customizable load limit feature.

There are other elements that are a basic part of the AMI, such as the underlying communication infrastructure, the central Meter Data Management systems or the intermediate meter data concentrators. The AMI’s underlying communication infrastructure will be further explained in section 3.5. Meter data concentrators, or just data concentrators, are Intelligent Electronic Devices (IEDs) similar to RTUs that act as a gateway between MDM and smart meters. On the other hand, the Meter Data Management (MDM) system is a system comprised of several components, of which the customer records database is one of the most important. This database allows the DSO to manage large amounts of data generated by the meters under the control of the utility. Other processes which are managed by the MDM include managing the transmission of data records from the smart meters up to the back-office where the MDM is located, the storage process, protecting their privacy and integrity, as well as making all these data accessible to third parties such as energy marketers and retailers or energy services providers. To this respect, the MDM has to validate and provide the necessary mechanisms to guarantee that AMI data is complete and accurate despite disruptions in the communications network or at customer premises.

Some of the main features that are defined in the smart grid are the chance for customers to not only consume power but also to produce it (i.e. installing local energy generators such as



solar panels), what is called “prosumers”, the possibility of having an Electric Vehicle (EV) which can be connected to the grid anywhere and anytime, and allowing for demand response applications based on dynamic tariff signalling and connection/disconnection features (also called load shedding). AMI together with local energy management systems are key elements for achieving these objectives. Energy Management Systems (EMS) are related with the concepts of Smart Home/building/business/industry. These systems are becoming directly interdependent with the automation of the home, business, building or industry activity. For instance, home and building automation may include centralized control of lighting, HVAC (heating, ventilation and air conditioning), appliances, and other systems, to provide improved comfort, energy efficiency and security. Home Energy management systems might connect electric smart meters with smart appliances such as television, washing machines, dishwasher, as well as to home automation systems or even to future smart meters targeting the heating, gas and water sectors. The key objective here is to efficiently manage energy aspects, by for instance turning off/on an appliance, switching off lights and raising blinds, etc.

3.5 Communications networks in the smart grid

As already mentioned in 1.1, the smart grid can be defined as an upgraded electricity network to which two-way digital communication between supplier and consumer, intelligent metering and monitoring systems have been added. As it might be already clear from the previous descriptions, the smart grid is intrinsically dependant on a unified network platform which interconnects all devices within the electric power infrastructure.

The underlying communications infrastructure should be able to connect different elements, such as smart meters and substations to the back office (e.g. operation centres). Besides it should support control and management functions as well as smart grid applications such advanced metering, demand response, ADA, etc. To this respect, the communication layer should enable both remote control from grid control centres and retrieval of data on loads, interruptions and other electrical events from all substations in the grid. Moreover the communication layer must also allow the data transmission to the back office departments for protection engineering, maintenance and for planning and asset management.

The smart grids’ envisioned communication infrastructure spans the different domains, including transmission, distribution and even the customer premises. In the following figure the reader will find a schematic representation of how the communication layer will support the operations of the power system.



Figure 5 the power system and its underlying communication infrastructure (based on (14))

According to the literature the smart grid underlying communication infrastructure can be further divided into different components. The following lines try to present a consensus-based overview of the most common terms used to name this components as well as their main role in the whole architecture.

3.5.1 Communication networks at the customer premises

Inside the customer premises, and depending if this is a big industry, a small business or regular home end user, or even if it is a smart building (e.g. modern office buildings), it can be distinguished between the Home Area Network, the Business/Building Area Network and the Industrial Area Network.

The Home Area Network (HAN) effectively manages the on-demand power requirements of the end-users. This network is envisioned to interconnect smart electric appliances such as television, washing machine, dishwasher, smart meters, energy management systems, etc. It is the supporting infrastructure for demand-response applications (i.e. switching smart appliances on or off in order to make an efficient use of electric tariffs) and advanced energy services provided by DSOs and retail energy or new energy services providers. This network can also provide the integration between home automation equipment and energy management systems and is directly related to the concept of Smart Home.



The Business/Building Area Network (BAN) – also known as Commercial Area Network – is a communication infrastructure intended to support the needs of a regular business (e.g. office building). The power demand of businesses and/or smart buildings is significantly higher than those from households and its pattern follows a different curve, with peaks in the morning and afternoon. Business Energy Management Services and Building Automation as well as other advanced energy services such as the management of local generation (i.e. solar panels on the roof) are some of the applications that need to be supported by the BAN. On the other hand, a group of HANs is sometimes also called a BAN. In this case, the network includes all communications in one Building due to its size. The BAN network is directly related with the concept of Smart Building.

To end up with the different networks present at the customer premises, the Industrial Area Network (IAN) can be defined as the communication infrastructure that allows the interconnection and supports the control of all machines and devices necessary in a particular industry, including regular ICT stuff such as computers, printers and servers, but also Industrial Control Systems (ICS) such as PLCs, assembly robots, Distributed Control Systems, etc.

3.5.2 Communication networks supporting distribution-related information technologies and applications

The last mile communication infrastructure of the smart grid is a two-way communications network generally overlaid on top of the power distribution system, which allows for advanced metering services, distribution automation, substation automation, etc. In the literature this segment of the smart grid underlying communication infrastructure can be named as Neighbourhood Area Network (NAN), Field Area Networks (FAN), or Advanced Metering Infrastructure (AMI), depending on the devices it interconnects and the supported applications. For instance, FANs are considered to connect the distribution substations, the distributed/feeder/transformer centre field devices, and DERs/microgrids, including the utility scale electric storage, to the utility control and operation centre (14). In addition to these systems, NANs also include smart meters in households, industry and businesses. Likewise, the AMI term can be used interchangeably with NANs but might also only interconnect smart meters with back-office systems, excluding distribution substation automation or transformer centres systems and DER-related elements.

The last mile networks (i.e. AMI, NAN, FAN) as well as DERs/microgrids and other distribution substation networks are interconnected with utility control and operations via the backhaul network. The backhaul can be owned and managed by the utility (i.e. DSO) or by a third party, such as a public telecommunications service provider. Typically, last mile networks have access to more than one backhaul network. Backhaul networks can use wireline or wireless technologies and enable the aggregation and transportation of customer-related smart grid telemetry data, substations automation critical operations data, relevant field data of microgrids and DER, and mobile workforce information.

Another relevant communication infrastructure is the distribution substation network. This infrastructure interconnects devices within a distribution substation. It is comprised of LANs



that contain the local SCADA, IEDs, Remote Terminal Units, PMUs, and other field devices that need to be remotely controlled and monitored. At the same time the distribution substation network provides connectivity to the backhaul network, either by directly connecting to backhaul network connection point or indirectly via de the FAN network, which in turn can interconnect several distribution substations before accessing the backhaul. Transformer centres networks can be seen as a reduced version of a distribution substation network and might typically include RTUs, PMUs or even smart meters concentrators. The LANs interconnecting these devices might have direct communication with the backhaul network or indirect connection via the FAN.

The last relevant communication infrastructure supporting power distribution operations – DER/microgrids will be addressed in 3.5.5 – is the feeder network. This network help exchanging information with field devices such as reclosers, switches, capacitor banks and other sensors and IEDs supporting distribution automation and which are distributed along the power lines, substations and transformer centres. It might be considered as an overlay on the electrical grid and can make use of wireless and wireline communication technologies. The name given to this network intrinsically bounds it to the distribution domain. Besides, the IEEE P2030 standardisation (14) describes it in this way. However, it might also be extended analogously to the transmission domain, where PMUs and other IEDs will be deployed for WAMs and other monitoring and control applications.

3.5.3 Communication networks supporting transmission-related information technologies and applications

One of the most relevant communication infrastructures exclusively related to the transmission domain is the transmission substation network. There are other communication infrastructures as important but these will be explained in section 3.5.4 since they can be found either in distribution or transmission operations. Similarly to the distribution substation networks, transmission substation networks are normally LAN networks interconnecting devices such as a local SCADA, IEDs, RTUs, PMUs, and other field devices that need to be controlled and monitored via the WAN/backhaul network.

3.5.4 Common Communication networks supporting transmission and distribution

There are several communication infrastructures that share similar purposes either if the utility is a Distribution System Operator (DSO) or a Transmission System Operator (TSO). The most relevant of these infrastructures will be explained in the following lines.

The Utility Local Area Network can be seen as a network which is comprised of utility operations and enterprise LANs to manage operations, control and enterprise processes and services (14). This is where the back-office infrastructure such as the utility control centres or the AMI head-end is located. The Utility LAN interconnects either to the public Internet or to Wide Area Network (WAN) through secure communications so as to exchange customer data to third party providers.



Another important infrastructure common to both TSOs and DSOs is what might be called Regional Interconnection Networks. These networks connect the utilities communications networks to other utilities networks, either through their own proprietary networks or through public carrier backbones. For instance, these networks might interconnect several control centres of one the same DSO.

As it has been already introduced, and spanning – and sometimes even superseding – the Regional Interconnection Network and the backhaul networks one could find Wide Area Networks (WAN). Wide Area Networks are comprised of the core network/backbone that connects to major service provider backbones or inter-utility backbones. These networks might provide secure interconnection to the public Internet network, transmission substations and utility control and enterprise/IT networks.

3.5.5 Communication networks at the generation domain

Inside this category two different communication infrastructures can be identified, those networks inside plants devoted to bulk generation, and those supporting microgrids and DERs.

Bulk generation networks facilitate large-scale power generation. These networks normally include isolated PLC-based networks, Distributed Control System networks, field buses, SCADA LANs and interconnecting infrastructures. Moreover, business-related regular ICT gear can also be found in bulk generation networks, which might include servers devoted to supporting corporate services, personal computers, WiFi networks, etc.

On the other side, DER or microgid networks are communication infrastructures devoted to supporting the integration in the smart grids of all renewable and non-renewable sources (e.g., wind, solar, diesel), not part of the centralized energy generation and normally in the range of low-medium power. According to (14) “these energy resources could be interconnected through a LAN. Access communications gateways can then connect these DERs and storage LAN networks to the main grid, creating grid-connected energy sources”.

3.5.6 The role of the Internet in the smart grids

The public Internet may be the primary communication path between utility enterprise data centres, market, and third-party energy providers. For instance, utility contractors and vendors are used to provide support to the utility via VPN networks traversing the public Internet. Moreover, data exchange among DSOs and between DSOs and TSOs might also make use of secure channels over the public Internet.

On the other hand, energy management services may be offered to customers by third-parties (e.g. retailers, energy service providers, etc.), utilities, via the Internet. Moreover, thanks to the Internet it is also expected that end users may monitor and control many integrated home automation and energy management services from their work-place or mobile phones.



3.6 Communication technologies

The previous section introduces the most relevant networks of which the smart grid communication architecture is comprised. This section provides an overview on the technologies used to transfer data, commands, and other necessary information for the proper operation of the smart grids.

The information is presented in a table format, where two different tables provide the most relevant information about communication technologies in the smart grid. Table 2 provides an overview on the main application-level communication protocols and related standards for each of the different smart grid applications (i.e. Energy management automation, advanced distribution and transmission automation, microgrids, and control centres). This information is greatly based on the draft version of the deliverable of WP 2.3 from the DG CONNECT’s Ad-Hoc EG on smart grids security (30). On the other hand, Table 3 presents the most relevant communication technologies, focusing on the media used (i.e. power line, fibre optics, etc.) as well as on the communication protocols at all the low levels defined by the ISO reference communication model. This information is presented based on the most relevant network components defined in section 3.5. It is important to highlight that none of the following tables include proprietary protocols, which by the way, are quite common in domains such as distribution automation or power generation.

Smart Grid Application App. level comm. protocols and related standards

Horizontal protocols Management: Telnet, SSH, HTTP/HTTPS, SNMP

Time synchronisation: SNTP, NTP, IEEE 15888

Redundancy: IEC 62439, RSTP, MRP, PRP, HSR, CRP, BRP

Advanced Metering and Energy Management Automation (HAN, BAN, IAN)

Metering: DLMS/COSEM (IEC 62056), OpenHAN

Energy Management Automation: ZigBee/IEEE 802.15.4, BACnet, LonWorks

Note: ZigBee’s application profiles for Energy Management Automation include HA (Home Automation), Building Automation (CBA).

Advanced Distribution Automation/Transmission Automation

IEC 61850 (with MMS for client-server communications and GOOSE for real-time communications)

IEC 60870-5 (IEC 101, 104 and DNP3)

ZigBee/IEEE 802.15.4 Smart Energy (SE) application profile

Note: IEC 62351 defines the security aspects of IEC 61850.

Distributed Energy Resources and Microgrids

IEC 61850 (with the data model extension defined in IEC 61400 for windmills and of IEC 61850-7-420 for all the



rest of distributed energy resources, and IEC 61850-7-410 for hydro power plants)

IEC 60870-5-101/104, DNP 2.0 can also be used, but the aforementioned are preferred.

Note: IEC 61850 is based on MMS (therefore IEC 62351 is also applicable here). On the other hand IEC 61400 can be based on OPC and Web Services.

Control Centres Inter-control centre communication: IEC 60870-6 TASE.1 and TASE.2 variants.

Transmission control centres: IEC 61698-13 CIM RDF Model exchange format for distribution, IEC 61670-5xx series.

Distribution control centres: IEC 61670-452 CIM RDF Model exchange format for transmission.

Note: TASE.1 is also known as ELCOM, while TASE.2 is also known as ICCP. Besides, IEC 62351 part 3 describes the basic security aspects of TASE.1 and TASE.2.

Table 2 Application level communication protocols and related standards in the smart grid

Smart Grid Application Communication media and low-level protocols

Customer Premises Networks (HAN, BAN, IAN)

Wired: Power Line, HomePlug, Ethernet, serial, TokenRing.

Wireless: ZigBee/IEEE 802.15.4

Medium independent protocols: TCP/IP suite, BACnet/IP.

Last mile networks (FAN, NAN, AMI)

Wired: BPL (PLC), DLC (PLC), fibre, twisted pair, PDH, SONET/SDH, xDSL, POTS, PRIME, Meters&More, ANSI C12.18, ANSI C12.21.

Wireless: radio frequency, microwave, cellular, GPRS, UMTS, LTE, IEEE 802.16 (WiMAX).

Medium independent: TCP/IP suite, ANSI C12.22.

Substation Networks (Distribution and Transmission)

Wired: Satellite, Ethernet, xDSL.

Wireless: radio frequency, cellular, LTE, UMTS, GPRS.

Medium independent: TCP/IP suite.

Backhaul Network Wired: twisted pair, cable, fibre optic, POTS, SDH/SONET, PPP.

Wireless: cellular, microwave, radio frequency, 3G,



WIMAX, LTE, paging.

Medium independent: Frame Relay, ATM, MPLS, TCP/IP suite, IPSec.

Regional Interconnection Networks/WAN networks

Wired: fibre rings, leased lines, SONET/SDH, WDM, PPP.

Wireless: satellite.

Medium independent: ATM, Frame Relay, MPLS, TCP/IP suite, IPSec.

Utility LAN Wired: fibre, twisted pair, serial, Token Ring, Ethernet, xDSL, PPP.

Wireless: radio, paging, IEEE 802.11, IEEE 802.15.4/ZigBee

Medium independent: TCP/IP suite

Bulk Generation Networks and DER/Microgrids networks

Wired: serial, Ethernet, PPP.

Wireless: radio, IEEE 802.15.4/ZigBee

Medium independent: TCP/IP suite

Table 3 Communication media and low-level protocols



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5 Abbreviations ADA Advanced Distribution Automation

AMI Advanced Metering Infrastructure

AMR Advanced Metering Reading

ANSI American National Standards Institute

ATM Asynchronous Transfer Mode

BAN Building Area Networks

BPL Broadband over power line

BRP Beacon Redundancy Protocol

CBA Building Automation

CECRE Control Centre of Renewable Energies

CEN European Committee for Standardization

CENELEC European Committee for Electrotechnical Standardization

CH4 Methane

CIIP Critical Information Infrastructure Protection

CIM RDF Common Information Model Resource Description Framework

CO2 Carbon dioxide

COSEM COmpanion Specification for Energy Metering

CRP Cross-network Redundancy Protocol

DCA Distribution Contingency Analysis

DCS Distributed Control System

DER Distributed Energy Resources DG

CONNECT Directorate General for Communications Networks, Content and Technology

DLC Data Link Control

DLF/DLE Distribution Load Forecasting and Estimation

DLMS Device Language Message specification

DLR Dynamic Line Ratings

DNP Distributed Network Protocol

DoE Department of Defense

DPF Distribution Power Flow

DR Demand-Response

DSE Distribution State Estimation

DSL Digital Suscriber Line

DSO Distribution System Operators

EC European Commission

EG Expert Group

EISA Energy Independence Security Act

EMS Energy Management System



ENISA European Network and Information Security Agency

ESO European Standardisation Organisations

ETP European Technology Platform

ETSI European Telecommunications Standards Institute

EU European Union

EV Electric Vehicule

FAN Field Area Network

FDIR Fault Detection Isolation and Restoration

GDP Gross domestic product

GOOSE Generic Object Oriented Substation Events

GPRS General Packet Radio Service

HA Home Automation

HAN Home Area Network

HMI Human Machine Interface

HSR High-availability Seamless Redundancy

HTTP Hypertext Transfer Protocol

HTTPS Hypertext Transfer Protocol Secure

HVDC High-Voltage Direct Current

IAN Industrial Area Networks

ICCP Intercontrol Center Communications Protocol

ICS Industrial Control Systems

ICT Information and communications technology

IEA International Energy Agency

IEC International Electrotechnical Commission

IED Intelligent Electronic Devices

IEEE Institute of Electrical and Electronics Engineers

IP Internet Protocol

IPSec Internet Protocol Secure

ISO International Organization for Standardization

IT Information Technology

IVVC Integrated Voltage/Var Control

LAN Local Area Network

LTE Long Term Evolution

LV Low Voltage

MAN Metropolitan Area Network

MDM Mobile Device Management

MMS Microsoft Media Server

MPLS Multiprotocol Label Switching

MRP Multiple Registration Protocol

MV Medium Voltage



N20 Nitrous Oxide

NAN Neighbourhood Area Network

NIST National Institute of Standards and Technology

NTP Network Time Protocol

OFC Optimal Feeder Configuration

OMS Outage Management System

PDH Plesiochronous Digital Hierarchy

PLC Power Line Communications

PMU Phasor Measurement Units

POTS Plain Old Telephone Systems

PPP Point-to-Point Protocol

PRIME PoweRline Intelligent Metering Evolution

PRP Parallel Redundancy Protocol

RSTP Rapid Spanning Tree Protocol

RTP Real-Time Pricing

RTU Remote Terminal Units

SCADA Supervisory Control and Data Acqusition

SDH synchronous digital hierarchy

SE Smart Energy

SNMP Simple Network Management Protocol

SNTP Simple Network Time Protocol

SONET Synchronous optical networking

SP Special Publication

SSH Secure Shell

TASE Telecontrol Application Service Elements

TCP Transmission Control Protocol

Telnet Telecommunications Network

TP Topology Processor

TSO Transmission System Operators

UMTS Universal Mobile Telecommunications System

USA/US United States of America

VPN Virtual Private Network

WAM Web Application for Management

WAMS Wide Area Monitoring System

WAN Wide Area Networks

WiFi Wireless Fidelity

WiMAX Worldwide Interoperability for Microwave Access







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