To the extent that the popular media understands the Smart Grid at all, it’s seen in terms of “smart meters” that are going to, say, let the utilities turn off consumers’ clothes dryers. Yet it really is about three things: the currently fragile grid, which desperately needs fixing; the fact that no matter where somebody wants to site a new power plant or run power lines, a whole lot of people are going to resist it fiercely; and the business reality that electricity is a commodity and wants to be traded like one.
A further factor is that the governments of the European Union, China, and the United States are pouring billions of Euros, Yuan, and dollars into their smart grids for technology that does not yet exist or exists today in a hundred different forms that defy interoperability and must be reconciled. Technologists have a wonderful opportunity to do it right and get paid for it.
It helps to understand what everyone is talking about. The National Institute of Standards and Technology, (NIST), the IEEE Power Engineering Society (PES), and hundreds of companies have been working on defining the Smart Grid in terms of standards for guiding engineers in designing actual Smart Grid products that go far beyond electric meters. In fact, the needs of the Smart Grid are largely in the realm of information-technology—wired and wireless networking, monitoring, control, and information processing.
Most of the information here comes from the 145-page “NIST Framework and Roadmap for Smart Grid Interoperability Standards, Release 1.0,” which was released at the January 19 joint IEEE/NIST Innovative Smart Grid Technologies conference in Gaithersburg, Md. The conference drew roughly 700 attendees to its three days of panels and technical sessions, despite the fact that its planning had only kicked off in October (see “IEEE And NIST Smart Grid Conference Hits The Ground Running”).
Communications penetrates all of the aspects of the Smart Grid, as indicated by the roadmap’s list of the 25 most important standards (see the table) that NIST and the other stakeholders are developing. The list is heavily weighted toward information technology and information security.
To facilitate discussions about the Smart Grid, a “conceptual model” detailed in the report and elsewhere describes the Smart Grid in terms of domains (customers, markets, service providers, operations, bulk generation, transmission, and distribution), which are functional designations of user classes. The model also refers to actors, applications, associations (logical connections), and interconnections (physical connections). Watch for that “actors” term in what follows, because it usually signals a piece of hardware that needs to be designed.
The usual way of presenting the Smart Grid conceptual model is hierarchically by domains, starting with the customer and working backward to bulk generation, transmission, and generation. There is a fairly simple diagram of the overall set of domains (Fig. 1) (and other diagrams that represent each domain), but it doesn’t show the interdependence of domains. An alternative diagram illustrates just how complex Smart Grid interactions (Fig. 2) will be, although it tends to induce headaches from eyestrain.
To highlight what is revolutionary about the Smart Grid, I’m going to explain the domains out of their usual order, emphasizing financial transactions over operational considerations. That means starting with the markets.
THE MARKETS DOMAIN
Not everyone would agree, but the markets domain is what makes the Smart Grid smart. It’s a commodities exchange where electricity and electricity futures are bought and sold. (Companies like the unlamented Enron do that now, but not in near real-time.)
Actors in the markets domain exchange prices and balance supply and demand within the power system. The boundaries of the market domain include the edge of the operations domain and of the domains that supply assets that make electricity and get it to the consumer (generation, transmission, etc.) and the customer domains.
The function of the market domain in setting electricity prices takes the Smart Grid beyond the “simple” role of a continent-spanning industrial-control system. Its financial aspect gives its communications aspects the imperative for traceability and auditability. Communications must support e-commerce standards for integrity and non-repudiation.
That’s going to be an evolving technical area. As the percentage of energy supplied by small distributed energy resources (DERs) increases, the allowed latency in communications with these resources must shrink.
The NIST report notes that “The high-priority challenges in the markets domain are: extension of price and DER signals to each of the customer sub-domains; simplification of market rules; expanding the capabilities of aggregators; interoperability across all providers and consumers of market information; 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 domains.”
As defined in the NIST report, the markets domain actors comprise market managers, retailers, aggregators, and traders. Market managers include independent systems operators (ISOs) for wholesale markets or the New York and Chicago Mercantile Exchange (NYMEX/CME) for forward markets. There also are transmission and services and demand response markets as well as basic electricity markets.
“Retailers sell power to end customers and may in the future aggregate or broker DER between customers or into the market. Most are connected to a trading organization to allow participation in the wholesale market,” the report says.
“Aggregators combine smaller participants (as providers or customers or curtailment) to enable distributed resources to play in the larger markets,” it continues. “Traders are participants in markets, which include aggregators for provision and consumption and curtailment, and other qualified entities. There are a number of companies whose primary business is the buying and selling of energy.”
THE SERVICE PROVIDER DOMAIN
In the service provider domain, “services” are functions like billing and customer account management that support the business processes of power system producers, distributors, and customers. Major challenges include maintaining the cyber security, reliability, stability, integrity, and safety of the electrical power network.
The service provider domain shares interfaces with the markets, operations, and customer domains. Communication with the operations domain provide system control and situational awareness. Communication with the markets and customer domains will support new “smart” services, particularly customer interaction with the market(s).
THE CUSTOMER DOMAIN
The Smart Grid is fundamentally about decreasing power consumption and increasing power generation as customers become active participants in the supply chain.
The customer domain is usually segmented by typical demand into sub-domains for home (less than 20 kW), commercial/building (20 to 200 kW), and industrial (greater than 200 kW). Each sub-domain has multiple actors and applications, and each has a meter actor and an energy services interface (ESI) that may reside in the meter, on an energy management system (EMS), or in an independent gateway.
The ESI is the primary service interface. It may communicate with other domains via the advanced metering infrastructure (AMI) or some other means, such as the Internet. The ESI communicates to devices and systems within the customer premises across a home-area network or other local-area network.
The EMS is the entry point for applications like remote load control, monitoring and control of distributed generation, in-home display of customer usage, reading of non-energy meters, and integration with building management systems and the enterprise. It may also provide auditing/logging for cyber security.
There may be more than one EMS— and therefore more than one communications path—per customer. The customer domain is electrically connected to the distribution domain and communicates with the distribution, operations, market, and service provider domains. Importantly, the customer domain may also provide micro-generated electricity to the grid.
THE OPERATIONS DOMAIN
Actors in the operations domain are responsible for the smooth operation of the power system. These are some of the people in hardhats in the trucks and the workers who support them in the office.
In transmission operations, utilities use EMSs, while distribution operations employ similar distribution management systems. Under the Smart Grid, responsibility is likely to migrate from the regulated utilities to a new class of power business—outsource service providers.
THE BULK GENERATION DOMAIN
The bulk generation domain involves any kind of electrical generation: combustion, nuclear fission, flowing water, wind, solar radiation, or geothermal heat. The boundary of this domain is typically the transmission domain, to which it is hard-wired. But the bulk generation domain also shares interfaces with the operations and markets domains.
This domain must communicate performance and quality-of-service issues such as scarcity (especially for wind and sun) and generator failure that may affect the routing of electricity onto the transmission system from other sources. A lack of supply may be addressed directly (via operations) or indirectly (via markets). Actors include devices such as protection relays, remote terminal units, equipment monitors, fault recorders, user interfaces, and programmable-logic controllers.
THE TRANSMISSION DOMAIN
In this context, transmission is the bulk transfer of electrical power from generation sources to distribution through multiple substations. The domain may contain DERs such as electrical storage or peaking generation units.
The network is typically operated by a regional transmission operator (RTO) or independent system operator (ISO) whose primary responsibility is maintaining stability on the electric grid by balancing generation (supply) with load (demand).
Actors include remote terminal units, substation meters, protection relays, power quality monitors, phasor measurement units, sag monitors, fault recorders, and substation user interfaces. Capacity that can be dispatched when needed is procured through the markets domain, scheduled and operated from the operations domain, and delivered to the customer domain through the transmission domain.
THE DISTRIBUTION DOMAIN
The distribution domain encompasses the electrical interconnection between the transmission domain and the customer domain. The wokers here are the hardhats in your own neighborhood and the people in the office who dispatch them. It includes the metering points for consumption, distributed storage, and distributed generation. Reliability varies with structure, types of actors, and degree to which they communicate with each other and with the actors in other domains.
Historically, distribution system topologies have been radial, with little telemetry, i.e., almost all communications within the domain were performed by humans with telephones and two-way radios. In the Smart Grid, the distribution domain will communicate more closely with the operations domain in real time, managing power flows associated with the markets domain. In some scenarios, third-party customer service providers may communicate with the customer domain using the infrastructure of the distribution domain.
For a look at one aspect of the Smart Grid from the standpoint of someone in the distribution domain, see “Anticipating Unanticipated Consequences.”
The “actors” in the conceptual model signal opportunities for new hardware designs. How can a designer get a handle on what should go into those designs? Here are some more clues. To prioritize its standards work, NIST chose key functionalities plus cyber security and network communications. Its list provides a menu of potential work areas:
• Wide-area situational awareness: Power-system components and performance should be monitored and displayed across interconnections and over large geographic areas in near real time.
• Demand response and consumer energy efficiency: These are mechanisms and incentives for utilities, business, industrial, and residential customers to cut energy use during times of peak demand or when power reliability is at risk.
• Energy storage: Today, that’s mostly about pumped hydroelectric storage—pumping water from a lower lake to a higher lake with a dam at night and recovering the energy during the day. That’s low-tech but effective. However, NIST points out, “New storage capabilities—especially for distributed storage—would benefit the entire grid, from generation to end use.”
• Electric transportation: This is primarily about enabling the large-scale integration of plug-in electric vehicles (PEVs) with the grid.
• Cyber security: It’s necessary to ensure the confidentiality, integrity, and availability of electronic information communication systems and grid-control systems
• Network communications: Since the Smart Grid domains and subdomains will use a variety of public and private communication networks, we need performance metrics and standards for operational requirements.
• AMI: Utilities really want AMI so they can implement residential demand response via dynamic pricing. AMI comprises the communications hardware and software plus system and data management software for a two-way network between advanced meters and utility business systems.
• Distribution grid management: This is about new ways of maximizing the performance of feeders, transformers, and other components of networked distribution systems and integrating with transmission systems and customer operations.
AT THE CONSUMER
“The interface between the Smart Grid and the customer domain is of special importance. It will be the most visible part of the Smart Grid to the consumer,” the NIST report says. As noted earlier, the conceptual reference model divides the interface to the customer domain into the meter and the ESI. That ESI is the gateway to the customer premises network.
The meter and the ESI measure and record electricity usage, communicating that data upstream to the service provider. They also handle all sorts of service provisioning and maintenance functions, such as troubleshooting and remote connection and disconnection of service. Most importantly, this is where pricing and demand response signaling occurs.
There are many “blue-sky” opportunities for design here. “New and innovative energy-related services, which we may not even imagine today, will be developed and may require additional data streams between the Smart Grid and the customer domain,” the NIST report says. “The diversity of communications technologies and standards used by devices in the customer domain presents a significant challenge to achieving interoperability. In addition, ensuring cyber security is a critical consideration.”
It’s helpful to understand the distinction between the meter and the ESI, which the report considers “a very important forward-looking aspect of the reference model.”
Beyond measuring, recording, and sending information about electricity usage, the meter must also measure the flow of power back into the grid from distributed generation or storage resources located at the customer’s premises.
There are a number of design issues associated with the meter’s ownership. Early experiences with smart meters in test markets in California demonstrate a need for meter manufacturers to work closely with their utility customers, so the people at the utility who deal first-hand with the public fully understand how the things work. An inability to answer an audience question like “Does the smart part of the meter get its power from your side of the meter or mine?” at a town-hall meeting really throws cold water on a beta-test.
Distrust arises because, unlike everything else at the customer’s premises, the meter belongs to the service provider, which may or may not be the same company as the electric utility.
Perhaps designing an ESI looks more appealing. If you’re designing an ESI, remember that it’s an information management gateway through which the customer interacts with energy service providers. ESI standards must allow for innovation in market structures and services. Its basic functions demand response signaling such as price/kWh information, but the possibilities for more advanced services are limitless.
One of the differences between residential environments and commercial/industrial environments is the level of sophistication and customer participation that can be assumed in configuring premises networks to achieve interoperability and security in Smart Grid communications.
Although many homes already have one or more data networks that interconnect computers or consumer electronic devices, this is not universally true. Even in homes that have data networks, consumers may not care to configure appliances to communicate over their home network. Anyone who is not a hard-core technophile would prefer to purchase, for example, a Smart Grid plug-and-play clothes dryer.
In a similar vein, many physical data communication interfaces—wireless and wired—are available for the home environment. It’s is a virtual Tower of Babel. Possibly the efforts of the Home Grid Forum’s G.hn group will show the way.
Throughout the Smart Grid standards process, privacy is a serious concern. Smart meters are read often. Fed into Smart Grid networks, those readings could provide a detailed timeline of activities occurring inside the home. This data may point to a specific individual or give away sensitive data. This isn’t just a worry for the home marijuana farmer with a huge array of grow-lights. Finding out how much energy a manufacturing plant consumes per shift can be an element of industrial espionage.
Additionally, privacy issues arise from the question of the legal ownership of the data being collected. With ownership comes both control and rights with regard to usage. If the consumer isn’t considered the owner of the data obtained from metering and home automation systems, the consumer may not receive the privacy protections provided to data owners under laws as they are written today.
Security is an even greater concern in an age of vulnerability to terrorism. Remember, we’re talking about the generation, transmission, and distribution of prodigious amounts of energy. Overall, the risk is high because Smart Grid information and controls flow through so many networks with so many owners.
To deal with that, NIST leads a Smart Grid Cyber Security Coordination Task Group (CSCTG) with more than 300 volunteer members from businesses, universities, regulatory organizations, and federal agencies. Cyber security requirements are being developed using a high-level risk assessment process. NIST has published a preliminary report, “NIST Interagency Report (NISTIR) 7628 Smart Grid Cyber Security Strategy and Requirements,” that describes the CSCTG’s overall cyber security strategy for the Smart Grid.
A new phase of the NIST plan has been formalized as the Smart Grid Interoperability Panel (SGIP). By mid-December 2009, one month after it was established, the SGIP membership exceeded 400 organizations divided among 22 stakeholder categories.
The SGIP’s function is to support the ongoing evolution of the Smart Grid Interoperability Framework; to identify and address additional gaps; to reflect changes in technology and requirements in the standards; and to provide ongoing coordination of SSO efforts to support timely availability of new or revised Smart Grid standards.
Comprehensive information on the stakeholder makeup of the SGIP, its meetings, and its findings is available at the NIST Smart Grid Collaboration Site.
A key element of the SGIP’s efforts is to ensure that a compromise in one network does not compromise security in other interconnected systems. A security compromise could impact the availability and reliability of the entire electric grid.
This introduces further opportunities for designers. Devices and applications in each domain are network end points. They include smart meters, appliances, thermostats, energy storage devices, electric vehicles, and distributed generation equipment at consumer sites.
Other devices in the transmission and distribution domains include phasor measurement units (PMUs) in a transmission line substation, substation controllers, distributed generation, and energy storage. The operations domain includes supervisory control and data acquisition (SCADA) systems and computers and display systems at the operation center.