Since the electric grid was built in the 1890s, technology has changed just as significantly and almost as rapidly as demand has increased. According to the Department of Energy, our current grid consists of more than 9,200 electric generating units, with more than 1 million megawatts of generating capacity connected to more than 600,000 miles of transmission lines. Despite those impressive numbers, the grid is running out of capacity because it’s being asked to do more than it was designed for…and its infrastructure is aging.
A modern, “smarter” grid will be more resilient, thanks to cutting-edge technologies, equipment, and controls that communicate to one another, according to the Office of Electricity Delivery and Energy Reliability. A smart grid can deliver power more efficiently and reliably, reduce outages, and allow end-users to manage their consumption and costs. Smart technology improves security, predicts events, creates balance by managing peak loads, and lowers costs. It also eases the integration of renewable energy sources.
The Customer Experience
Efficiency, availability, and reliability are the buzzwords most commonly associated with the smart grid, but there are also other benefits, such as faster restoration of power after disturbances; reduced peak demand, which lowers electric rates; lower operations costs for utilities and smaller bills for consumers; amplified integration of renewable energy sources and customer-owned power generation systems; and better security.
It’s been more than 10 years since Congress passed Title XIII of the Energy Independence and Security Act of 2007, providing legislative support for the DOE’s efforts to lead the modernization of the nation’s electric grid. During that time, tests have been conducted, standards and regulations written, and consumers educated about the choices they can make about their energy usage.
The smart grid’s digital technology, control systems, and computer processing enable two-way communication between the utility and the consumer, providing the information and tools for the former to respond to demand, outages, and failures, and the latter to adjust their usage. The information is possible due to advanced sensors that allow utilities to evaluate grid stability, digital meters that provide information to consumers and report outages, relays that sense faults in the substation, automated feeder switches that reroute power, and batteries to store energy, making it available to the grid when demand requires it.
“You must have a meter to get the data,” says Gary Bennett, vice president and general manager of Smart Energy America for energy and water, Honeywell Smart. “It all starts at the base with the meter. The meter must perform, have a long lifespan, and be robust.” Investment by the utility in smart metering plays a critical role.
Smart meters allow consumers to see how much electricity they use and when they use it. When combined with real-time pricing, the consumer can make decisions based on the data to save money by using less energy, particularly at peak times, when electricity costs are at their highest.
Smart meters allow utilities to enhance the customer experience and relationship, explains Ann Perreault, marketing director, Smart Energy, Honeywell Smart. “Meter data and connected devices create a new way to engage the customer by providing feedback for usage.” Analytics for strategy and outreach contribute to enriching the customer experience—what she calls the “Amazon experience” of providing insight into usage.
Smart grid technology is customer-driven, believes Kyle Garton, principal and product manager for AutoGrid. “We analyze data to help the customer make better decisions. Demand-response was a one-way conversation, but we have put in a customer engagement portal with feedback. We can forecast peak load, load shed, and events.”
They can also optimize dispatching to only specific customers who are called more to keep them in the program. “If we spread the load over more customers,” says Garton, “it helps [with] retention.”
Utility Company Benefits
Acquiring more data and more memory to manage the data can help a utility grow with the customer and expand its customer base. But too much data can be overwhelming. “We get the data into a single software platform for better visibility,” explains Garton. Bring the data into one place and integrate all systems. “You have to get all the systems and data into one site—not just smart data. Everything has to be connected for a customer-centric experience: seamless, flexible, and holistic.”
The key value lies in linking the utility with distribution and the customer, as well as connecting to energy storage, Garton continues. “We know the requirements of utilities: flexibility.” There are other requirements as utilities migrate to operating systems, he adds. Infrastructure is critical and security is a top concern. Integrated service to the utilities reduces security risks.
AutoGrid’s plan is to first get the data in one spot to do active controls with customer preferences while the utility manages the grid better. Once the data has been centralized, it can be rolled into programs to allow utilities to evaluate value streams. “The software automates those pieces,” says Garton. “Instead of the operator deciding on the platform, the software does it automatically.” It allows the utility to pinpoint where and when they need to deliver flexibility—distribution management. “They can guarantee load shed without violating customer contracts.”
That speaks to a recent trend: the desire of utilities to focus on end solutions, not just hardware and meter applications. “Utilities are looking for end-to-end solutions that cover metering, power generation, and cyber security,” says Bennet. The key is that technology should not be limited and should be agnostic in order to work with other systems.
The complexity is getting components to talk to each other, Peter Lilienthal, CEO of HOMER Energy, adds. They need the same voltage. That’s why he sees the industry moving toward a plug-and-play solution.
“Utilities are looking at broader end-to-end solutions that include cyber security and analytics,” confirms Bennet. “They want us to take a broader scope—to develop technology to solve problems.”
One of the problems they help solve is to identify locations where electricity is illegally leaving the grid. Preventing loss results in less generation, more reliability, lower operating costs, and enhanced revenue. Predicting outages and failures through analytics leads to reduced loss and less downtime.
Failure prediction analytics is part of a “best practices” approach Honeywell takes that includes examining peak demand, load balancing, and resources to improve output. “We understand and analyze hardware,” says Perreault. Serving in an almost consultant role, they help the utilities decide what works for them to reduce costs and improve revenue. “The number one problem for the utilities is that they have lots of data, but it has no value [if they can’t interpret it].”
The old rule of thumb says it’s important to follow all three A’s when it comes to data: acquire, analyze, act on. Not all utilities are capable of analyzing in order to know what action to take. Often, the amount of data collected is so overwhelming that little of it is actually used. Properly applied, analytics can determine how to integrate to other systems and manage them. “It’s a holistic view of resources,” adds Bennet.
Balance can mitigate costs. “The key is integrating the back office with the customer and the billing systems,” says Garton. A reduction from 14 portals to one in the back office improves operational efficiency for the utility.
Operational efficiency is an important factor for reducing costs and increasing reliability, but grid efficiency is also critical—and also achievable through smart technology. The resulting lower cost of operation is often passed on to the end-user in the form of lower rates, creating financial stability for utilities.
Managing demand during peak times saves money, enabling utilities to invest in capital upgrades—an advantage for those that need to upsize their distribution system in the expectation of load growth. Alternatively, Garton says, instead of upgrades, a utility can incentivize customers not to use electricity during peak demand. “You may need to save only a few megawatts [using] a few customers.” That flexibility optimizes the grid, he says.
Flexibility comes in many forms. Distributed energy (DE) is a macro trend, claims Gary Rackliffe, vice president of smart grids, North America, ABB Inc., but one that raises many questions, such as the economics of it or the feasibility of incorporating to the grid. “Siting distributed energy is complicated.” Any given location might be met with marginal prices based on bulk power production. “Cost is a factor. You have to ask: Can you produce it cheaper locally?”
Another question regards the capability of the local grid to host DE. “Utilities have concerns, like transfer tripping, interconnection requirements, and cost,” continues Rackliffe. It costs to trip off if a fault occurs, so controls will sometimes disconnect in the event of a fault. Investment in a control system can alleviate tripping. The integration of SCADA increases the reliability of the grid, optimizing the built transmission grid, off-shore.
Utilities also have to look at the capacity of the distribution grid and the needed investment, and then submit a plan for the distribution grid in terms of capacity investments, he continues.
Many utilities need to procure assets if they’re cheaper from a third party. “If it’s cheaper than adding capacity themselves, they have to look at alternatives,” says Rackliffe. In fact, California mandates that utilities look at DE resources as an alternative, but he cautions that whether the utility or a third party owns the assets, the utility must have the ability to dispatch service.
Ultimately, can DE alleviate the constraint in distribution and be offset? A peak in the feeder might be offset by DE to meet peak demand, for example.
Complicating the choice, there are different modes for DE. With behind-the-meter DE, power is owned by a private party and dispatched to the economic benefit of the owner. A generator behind the meter impacts the grid. There is more load behind the meter now, Garton indicates. “It’s not visible. It’s not predictable.”
“The utility may have to curtail, but not dispatch [behind-the-meter] generation,” explains Rackliffe. “They have to subtract must-run generation from the load.” Because of that, utilities are looking at microgrid applications with energy storage. “It’s more dispatchable.”
The ability to serve critical loads with local generation and centralized distribution onsite adds resiliency to the grid. “As a generator, it’s easier to connect to the distribution grid than locally because there are fewer restraints [than with utility-scale generation connecting to the grid],” points out Rackliffe. Don’t ignore centralized generation, he prophesies. It will dominate the near-term picture.
However, location can be a stumbling block. The challenge is that there may not be transmission lines close by. “Where is it windy? Where is the closest transmission line?” asks Rackcliffe. “Moving long distances is problematic.” The challenge with transmission extends beyond cost to right-of-way issues and the struggle of getting the lines built.
A utility-embedded microgrid provides resiliency if there’s a disturbance. “You can separate portions of the grid for repair in an emergency,” points out Rackliffe. In addition to resiliency, microgrids behind the meter are influenced by sustainability, the “green” factor, and cost. Now that the cost of solar and wind is more affordable, more microgrid systems are appearing.
Microgrids also serve in remote areas. An island system is not connected to the distribution grid and typically substitutes renewables such as solar or wind as the primary supply of electricity, with backup thermal storage, in order to avoid diesel, which Rackliffe says moves to a secondary function.
Three critical factors that impact DE include access to a local connection point, sufficient capacity to host DE on a feeder, and control to operate safely and to manage the voltage. While it’s considered a local issue, Rackliffe says that ultimately, it’s an overall system issue. “When you aggregate the load, net demand needs to be coordinated.”
It could be aggregated for efficiency, so it’s not sitting idle except for peak times. What happens when you aggregate load at the system level? “If a state has a 50% renewables portfolio, half may be hydro and a quarter might be wind and solar,” speculates Rackcliffe, “some of which is connected to the grid, but is also in DE. DE includes renewables connected to the distribution grid. It must be managed as part of dispatch, so, how do you meet peak demand? There’s no solar in the evening.”
The local impact of solar PV and the overall impact of solar affects grid investment. Rackcliffe says that solar PV panels are frequently seen on roofs in high-cost areas. “The driver behind it is that utility-scale solar dominates the market, but it depends on the payback.” Utility-scale solar is inexpensive to install and features an efficient tracking system, but it requires a substantial amount of space to generate power.
According to official market figures released by the Global Wind Energy Council, an international trade body, the world added 52 gigawatts of wind power in 2017. Total installed capacity is now 539,581 GW. Growth in wind power occurred in Asia, Europe, and North America, with power purchase agreements increasing in the US, thanks to large corporations such as Facebook and Apple.
Solar is distributed now, but with the “greenness” of power considered less important than cost, according to Lilienthal, utilities emphasize reliability and resilience. Recovery from outages resulting from disturbances in the distribution system is crucial.
But the bottom-line remains cost. Risk analysis reveals how robust a design is if rates, fuel prices, and storage costs change. “The goal is to find the lowest-cost design; you can’t do it with a spreadsheet,” says Lilienthal. Decision analysis requires a deep understanding of the scope of trade space in order to compare alternatives.
HOMER manufactures software for microgrid and distributed generation power system design and optimization that simulates how systems operate and provides data on how much fuel has been used, battery life, component wear, and cost of ownership. Some of the most important data relates to load—whether it’s seasonal or otherwise time-sensitive (daylight).
Hurricane Sandy changed things, Lilienthal says, because “backup generators don’t work on long-term outages.” This is where microgrids and renewable energy excel—but only if there is adequate storage. There are lots of storage choices. “How aggressive do you want to be on storage?” he queries. “What do you need power for? A/C? A well? There are several new battery storage options.”
Microgrids are effective before and after natural disasters, of course. Customers have discovered that, despite the challenge of a customer-owned local distributed network, they can save even more money by generating their own power—so much so that Lilienthal says the utilities in Hawaii are “pushing back” because they are losing revenue. “In the Cayman Islands, they issued demand charges to solar customers based on peak demand.”
There is a noticeable transformation of the grid, Garton states. What does the future look like? It’s evolving, but it centers on support for battery storage to improve renewables output, among other things.
The big thing is electric vehicles, AutoGrid’s Garton insists. Solar and storage affect the customer, but with solar, the utility has a good idea of when and where it will be installed. “With cars, there are no predictions. You get hot spots; large loads in homes appear overnight and sporadically, making it difficult for the utilities to manage. This trend is bigger than solar—and it will drive solutions like ours.”
Cloud storage has long been a trend. Honeywell offers cloud or service deployment of its software. “We enhance software through the cloud,” says Perreault.
There’s a new emphasis on having a distributed resource portfolio that can be leveraged in real time. Hybrid optimization of multiple energy resources provides reliability while SCADA systems insert control.
Numerous emerging technologies can complicate decisions. “A confused mind says no because the options are too overwhelming,” recognizes Lilienthal. The challenge is to find the time to educate the end-user and provide the tools to help customers understand the trade-offs.