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      A new method boosts wind farms’ energy output, without new equipment

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      Virtually all wind turbines, which produce more than 5 percent of the world’s electricity, are controlled as if they were individual, free-standing units. In fact, the vast majority are part of larger wind farm installations involving dozens or even hundreds of turbines, whose wakes can affect each other.

      Now, engineers at MIT and elsewhere have found that, with no need for any new investment in equipment, the energy output of such wind farm installations can be increased by modeling the wind flow of the entire collection of turbines and optimizing the control of individual units accordingly.

      The increase in energy output from a given installation may seem modest — it’s about 1.2 percent overall, and 3 percent for optimal wind speeds. But the algorithm can be deployed at any wind farm, and the number of wind farms is rapidly growing to meet accelerated climate goals. If that 1.2 percent energy increase were applied to all the world’s existing wind farms, it would be the equivalent of adding more than 3,600 new wind turbines, or enough to power about 3 million homes, and a total gain to power producers of almost a billion dollars per year, the researchers say. And all of this for essentially no cost.

      The research is published today in the journal Nature Energy, in a study led by MIT Esther and Harold E. Edgerton Assistant Professor of Civil and Environmental Engineering Michael F. Howland.

      “Essentially all existing utility-scale turbines are controlled ‘greedily’ and independently,” says Howland. The term “greedily,” he explains, refers to the fact that they are controlled to maximize only their own power production, as if they were isolated units with no detrimental impact on neighboring turbines.

      But in the real world, turbines are deliberately spaced close together in wind farms to achieve economic benefits related to land use (on- or offshore) and to infrastructure such as access roads and transmission lines. This proximity means that turbines are often strongly affected by the turbulent wakes produced by others that are upwind from them — a factor that individual turbine-control systems do not currently take into account.

      “From a flow-physics standpoint, putting wind turbines close together in wind farms is often the worst thing you could do,” Howland says. “The ideal approach to maximize total energy production would be to put them as far apart as possible,” but that would increase the associated costs.

      That’s where the work of Howland and his collaborators comes in. They developed a new flow model which predicts the power production of each turbine in the farm depending on the incident winds in the atmosphere and the control strategy of each turbine. While based on flow-physics, the model learns from operational wind farm data to reduce predictive error and uncertainty. Without changing anything about the physical turbine locations and hardware systems of existing wind farms, they have used the physics-based, data-assisted modeling of the flow within the wind farm and the resulting power production of each turbine, given different wind conditions, to find the optimal orientation for each turbine at a given moment. This allows them to maximize the output from the whole farm, not just the individual turbines.

      Today, each turbine constantly senses the incoming wind direction and speed and uses its internal control software to adjust its yaw (vertical axis) angle position to align as closely as possible to the wind. But in the new system, for example, the team has found that by turning one turbine just slightly away from its own maximum output position — perhaps 20 degrees away from its individual peak output angle — the resulting increase in power output from one or more downwind units will more than make up for the slight reduction in output from the first unit. By using a centralized control system that takes all of these interactions into account, the collection of turbines was operated at power output levels that were as much as 32 percent higher under some conditions.

      In a months-long experiment in a real utility-scale wind farm in India, the predictive model was first validated by testing a wide range of yaw orientation strategies, most of which were intentionally suboptimal. By testing many control strategies, including suboptimal ones, in both the real farm and the model, the researchers could identify the true optimal strategy. Importantly, the model was able to predict the farm power production and the optimal control strategy for most wind conditions tested, giving confidence that the predictions of the model would track the true optimal operational strategy for the farm. This enables the use of the model to design the optimal control strategies for new wind conditions and new wind farms without needing to perform fresh calculations from scratch.

      Then, a second months-long experiment at the same farm, which implemented only the optimal control predictions from the model, proved that the algorithm’s real-world effects could match the overall energy improvements seen in simulations. Averaged over the entire test period, the system achieved a 1.2 percent increase in energy output at all wind speeds, and a 3 percent increase at speeds between 6 and 8 meters per second (about 13 to 18 miles per hour).

      While the test was run at one wind farm, the researchers say the model and cooperative control strategy can be implemented at any existing or future wind farm. Howland estimates that, translated to the world’s existing fleet of wind turbines, a 1.2 percent overall energy improvement would produce  more than 31 terawatt-hours of additional electricity per year, approximately equivalent to installing an extra 3,600 wind turbines at no cost. This would translate into some $950 million in extra revenue for the wind farm operators per year, he says.

      The amount of energy to be gained will vary widely from one wind farm to another, depending on an array of factors including the spacing of the units, the geometry of their arrangement, and the variations in wind patterns at that location over the course of a year. But in all cases, the model developed by this team can provide a clear prediction of exactly what the potential gains are for a given site, Howland says. “The optimal control strategy and the potential gain in energy will be different at every wind farm, which motivated us to develop a predictive wind farm model which can be used widely, for optimization across the wind energy fleet,” he adds.

      But the new system can potentially be adopted quickly and easily, he says. “We don’t require any additional hardware installation. We’re really just making a software change, and there’s a significant potential energy increase associated with it.” Even a 1 percent improvement, he points out, means that in a typical wind farm of about 100 units, operators could get the same output with one fewer turbine, thus saving the costs, usually millions of dollars, associated with purchasing, building, and installing that unit.

      Further, he notes, by reducing wake losses the algorithm could make it possible to place turbines more closely together within future wind farms, therefore increasing the power density of wind energy, saving on land (or sea) footprints. This power density increase and footprint reduction could help to achieve pressing greenhouse gas emission reduction goals, which call for a substantial expansion of wind energy deployment, both on and offshore.

      What’s more, he says, the biggest new area of wind farm development is offshore, and “the impact of wake losses is often much higher in offshore wind farms.” That means the impact of this new approach to controlling those wind farms could be significantly greater.

      The Howland Lab and the international team is continuing to refine the models further and working to improve the operational instructions they derive from the model, moving toward autonomous, cooperative control and striving for the greatest possible power output from a given set of conditions, Howland says.

      The research team includes Jesús Bas Quesada, Juan José Pena Martinez, and Felipe Palou Larrañaga of Siemens Gamesa Renewable Energy Innovation and Technology in Navarra, Spain; Neeraj Yadav and Jasvipul Chawla at ReNew Power Private Limited in Haryana, India; Varun Sivaram formerly at ReNew Power Private Limited in Haryana, India and presently at the Office of the U.S. Special Presidential Envoy for Climate, United States Department of State; and John Dabiri at California Institute of Technology. The work was supported by the MIT Energy Initiative and Siemens Gamesa Renewable Energy. More

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      Energy storage important to creating affordable, reliable, deeply decarbonized electricity systems

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      In deeply decarbonized energy systems utilizing high penetrations of variable renewable energy (VRE), energy storage is needed to keep the lights on and the electricity flowing when the sun isn’t shining and the wind isn’t blowing — when generation from these VRE resources is low or demand is high. The MIT Energy Initiative’s Future of Energy Storage study makes clear the need for energy storage and explores pathways using VRE resources and storage to reach decarbonized electricity systems efficiently by 2050.

      “The Future of Energy Storage,” a new multidisciplinary report from the MIT Energy Initiative (MITEI), urges government investment in sophisticated analytical tools for planning, operation, and regulation of electricity systems in order to deploy and use storage efficiently. Because storage technologies will have the ability to substitute for or complement essentially all other elements of a power system, including generation, transmission, and demand response, these tools will be critical to electricity system designers, operators, and regulators in the future. The study also recommends additional support for complementary staffing and upskilling programs at regulatory agencies at the state and federal levels. 

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      Why is energy storage so important?

      The MITEI report shows that energy storage makes deep decarbonization of reliable electric power systems affordable. “Fossil fuel power plant operators have traditionally responded to demand for electricity — in any given moment — by adjusting the supply of electricity flowing into the grid,” says MITEI Director Robert Armstrong, the Chevron Professor of Chemical Engineering and chair of the Future of Energy Storage study. “But VRE resources such as wind and solar depend on daily and seasonal variations as well as weather fluctuations; they aren’t always available to be dispatched to follow electricity demand. Our study finds that energy storage can help VRE-dominated electricity systems balance electricity supply and demand while maintaining reliability in a cost-effective manner — that in turn can support the electrification of many end-use activities beyond the electricity sector.”

      The three-year study is designed to help government, industry, and academia chart a path to developing and deploying electrical energy storage technologies as a way of encouraging electrification and decarbonization throughout the economy, while avoiding excessive or inequitable burdens.

      Focusing on three distinct regions of the United States, the study shows the need for a varied approach to energy storage and electricity system design in different parts of the country. Using modeling tools to look out to 2050, the study team also focuses beyond the United States, to emerging market and developing economy (EMDE) countries, particularly as represented by India. The findings highlight the powerful role storage can play in EMDE nations. These countries are expected to see massive growth in electricity demand over the next 30 years, due to rapid overall economic expansion and to increasing adoption of electricity-consuming technologies such as air conditioning. In particular, the study calls attention to the pivotal role battery storage can play in decarbonizing grids in EMDE countries that lack access to low-cost gas and currently rely on coal generation.

      The authors find that investment in VRE combined with storage is favored over new coal generation over the medium and long term in India, although existing coal plants may linger unless forced out by policy measures such as carbon pricing. 

      “Developing countries are a crucial part of the global decarbonization challenge,” says Robert Stoner, the deputy director for science and technology at MITEI and one of the report authors. “Our study shows how they can take advantage of the declining costs of renewables and storage in the coming decades to become climate leaders without sacrificing economic development and modernization.”

      The study examines four kinds of storage technologies: electrochemical, thermal, chemical, and mechanical. Some of these technologies, such as lithium-ion batteries, pumped storage hydro, and some thermal storage options, are proven and available for commercial deployment. The report recommends that the government focus R&D efforts on other storage technologies, which will require further development to be available by 2050 or sooner — among them, projects to advance alternative electrochemical storage technologies that rely on earth-abundant materials. It also suggests government incentives and mechanisms that reward success but don’t interfere with project management. The report calls for the federal government to change some of the rules governing technology demonstration projects to enable more projects on storage. Policies that require cost-sharing in exchange for intellectual property rights, the report argues, discourage the dissemination of knowledge. The report advocates for federal requirements for demonstration projects that share information with other U.S. entities.

      The report says many existing power plants that are being shut down can be converted to useful energy storage facilities by replacing their fossil fuel boilers with thermal storage and new steam generators. This retrofit can be done using commercially available technologies and may be attractive to plant owners and communities — using assets that would otherwise be abandoned as electricity systems decarbonize.  

      The study also looks at hydrogen and concludes that its use for storage will likely depend on the extent to which hydrogen is used in the overall economy. That broad use of hydrogen, the report says, will be driven by future costs of hydrogen production, transportation, and storage — and by the pace of innovation in hydrogen end-use applications. 

      The MITEI study predicts the distribution of hourly wholesale prices or the hourly marginal value of energy will change in deeply decarbonized power systems — with many more hours of very low prices and more hours of high prices compared to today’s wholesale markets. So the report recommends systems adopt retail pricing and retail load management options that reward all consumers for shifting electricity use away from times when high wholesale prices indicate scarcity, to times when low wholesale prices signal abundance. 

      The Future of Energy Storage study is the ninth in MITEI’s “Future of” series, exploring complex and vital issues involving energy and the environment. Previous studies have focused on nuclear power, solar energy, natural gas, geothermal energy, and coal (with capture and sequestration of carbon dioxide emissions), as well as on systems such as the U.S. electric power grid. The Alfred P. Sloan Foundation and the Heising-Simons Foundation provided core funding for MITEI’s Future of Energy Storage study. MITEI members Equinor and Shell provided additional support.  More

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      New England renewables + Canadian hydropower

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      The urgent need to cut carbon emissions has prompted a growing number of U.S. states to commit to achieving 100 percent clean electricity by 2040 or 2050. But figuring out how to meet those commitments and still have a reliable and affordable power system is a challenge. Wind and solar installations will form the backbone of a carbon-free power system, but what technologies can meet electricity demand when those intermittent renewable sources are not adequate?

      In general, the options being discussed include nuclear power, natural gas with carbon capture and storage (CCS), and energy storage technologies such as new and improved batteries and chemical storage in the form of hydrogen. But in the northeastern United States, there is one more possibility being proposed: electricity imported from hydropower plants in the neighboring Canadian province of Quebec.

      The proposition makes sense. Those plants can produce as much electricity as about 40 large nuclear power plants, and some power generated in Quebec already comes to the Northeast. So, there could be abundant additional supply to fill any shortfall when New England’s intermittent renewables underproduce. However, U.S. wind and solar investors view Canadian hydropower as a competitor and argue that reliance on foreign supply discourages further U.S. investment.

      Two years ago, three researchers affiliated with the MIT Center for Energy and Environmental Policy Research (CEEPR) — Emil Dimanchev SM ’18, now a PhD candidate at the Norwegian University of Science and Technology; Joshua Hodge, CEEPR’s executive director; and John Parsons, a senior lecturer in the MIT Sloan School of Management — began wondering whether viewing Canadian hydro as another source of electricity might be too narrow. “Hydropower is a more-than-hundred-year-old technology, and plants are already built up north,” says Dimanchev. “We might not need to build something new. We might just need to use those plants differently or to a greater extent.”

      So the researchers decided to examine the potential role and economic value of Quebec’s hydropower resource in a future low-carbon system in New England. Their goal was to help inform policymakers, utility decision-makers, and others about how best to incorporate Canadian hydropower into their plans and to determine how much time and money New England should spend to integrate more hydropower into its system. What they found out was surprising, even to them.

      The analytical methods

      To explore possible roles for Canadian hydropower to play in New England’s power system, the MIT researchers first needed to predict how the regional power system might look in 2050 — both the resources in place and how they would be operated, given any policy constraints. To perform that analysis, they used GenX, a modeling tool originally developed by Jesse Jenkins SM ’14, PhD ’18 and Nestor Sepulveda SM ’16, PhD ’20 while they were researchers at the MIT Energy Initiative (MITEI).

      The GenX model is designed to support decision-making related to power system investment and real-time operation and to examine the impacts of possible policy initiatives on those decisions. Given information on current and future technologies — different kinds of power plants, energy storage technologies, and so on — GenX calculates the combination of equipment and operating conditions that can meet a defined future demand at the lowest cost. The GenX modeling tool can also incorporate specified policy constraints, such as limits on carbon emissions.

      For their study, Dimanchev, Hodge, and Parsons set parameters in the GenX model using data and assumptions derived from a variety of sources to build a representation of the interconnected power systems in New England, New York, and Quebec. (They included New York to account for that state’s existing demand on the Canadian hydro resources.) For data on the available hydropower, they turned to Hydro-Québec, the public utility that owns and operates most of the hydropower plants in Quebec.

      It’s standard in such analyses to include real-world engineering constraints on equipment, such as how quickly certain power plants can be ramped up and down. With help from Hydro-Québec, the researchers also put hour-to-hour operating constraints on the hydropower resource.

      Most of Hydro-Québec’s plants are “reservoir hydropower” systems. In them, when power isn’t needed, the flow on a river is restrained by a dam downstream of a reservoir, and the reservoir fills up. When power is needed, the dam is opened, and the water in the reservoir runs through downstream pipes, turning turbines and generating electricity. Proper management of such a system requires adhering to certain operating constraints. For example, to prevent flooding, reservoirs must not be allowed to overfill — especially prior to spring snowmelt. And generation can’t be increased too quickly because a sudden flood of water could erode the river edges or disrupt fishing or water quality.

      Based on projections from the National Renewable Energy Laboratory and elsewhere, the researchers specified electricity demand for every hour of the year 2050, and the model calculated the cost-optimal mix of technologies and system operating regime that would satisfy that hourly demand, including the dispatch of the Hydro-Québec hydropower system. In addition, the model determined how electricity would be traded among New England, New York, and Quebec.

      Effects of decarbonization limits on technology mix and electricity trading

      To examine the impact of the emissions-reduction mandates in the New England states, the researchers ran the model assuming reductions in carbon emissions between 80 percent and 100 percent relative to 1990 levels. The results of those runs show that, as emissions limits get more stringent, New England uses more wind and solar and extends the lifetime of its existing nuclear plants. To balance the intermittency of the renewables, the region uses natural gas plants, demand-side management, battery storage (modeled as lithium-ion batteries), and trading with Quebec’s hydropower-based system. Meanwhile, the optimal mix in Quebec is mostly composed of existing hydro generation. Some solar is added, but new reservoirs are built only if renewable costs are assumed to be very high.

      The most significant — and perhaps surprising — outcome is that in all the scenarios, the hydropower-based system of Quebec is not only an exporter but also an importer of electricity, with the direction of flow on the Quebec-New England transmission lines changing over time.

      Historically, energy has always flowed from Quebec to New England. The model results for 2018 show electricity flowing from north to south, with the quantity capped by the current transmission capacity limit of 2,225 megawatts (MW).

      An analysis for 2050, assuming that New England decarbonizes 90 percent and the capacity of the transmission lines remains the same, finds electricity flows going both ways. Flows from north to south still dominate. But for nearly 3,500 of the 8,760 hours of the year, electricity flows in the opposite direction — from New England to Quebec. And for more than 2,200 of those hours, the flow going north is at the maximum the transmission lines can carry.

      The direction of flow is motivated by economics. When renewable generation is abundant in New England, prices are low, and it’s cheaper for Quebec to import electricity from New England and conserve water in its reservoirs. Conversely, when New England’s renewables are scarce and prices are high, New England imports hydro-generated electricity from Quebec.

      So rather than delivering electricity, Canadian hydro provides a means of storing the electricity generated by the intermittent renewables in New England.

      “We see this in our modeling because when we tell the model to meet electricity demand using these resources, the model decides that it is cost-optimal to use the reservoirs to store energy rather than anything else,” says Dimanchev. “We should be sending the energy back and forth, so the reservoirs in Quebec are in essence a battery that we use to store some of the electricity produced by our intermittent renewables and discharge it when we need it.”

      Given that outcome, the researchers decided to explore the impact of expanding the transmission capacity between New England and Quebec. Building transmission lines is always contentious, but what would be the impact if it could be done?

      Their model results shows that when transmission capacity is increased from 2,225 MW to 6,225 MW, flows in both directions are greater, and in both cases the flow is at the new maximum for more than 1,000 hours.

      Results of the analysis thus confirm that the economic response to expanded transmission capacity is more two-way trading. To continue the battery analogy, more transmission capacity to and from Quebec effectively increases the rate at which the battery can be charged and discharged.

      Effects of two-way trading on the energy mix

      What impact would the advent of two-way trading have on the mix of energy-generating sources in New England and Quebec in 2050?

      Assuming current transmission capacity, in New England, the change from one-way to two-way trading increases both wind and solar power generation and to a lesser extent nuclear; it also decreases the use of natural gas with CCS. The hydro reservoirs in Canada can provide long-duration storage — over weeks, months, and even seasons — so there is less need for natural gas with CCS to cover any gaps in supply. The level of imports is slightly lower, but now there are also exports. Meanwhile, in Quebec, two-way trading reduces solar power generation, and the use of wind disappears. Exports are roughly the same, but now there are imports as well. Thus, two-way trading reallocates renewables from Quebec to New England, where it’s more economical to install and operate solar and wind systems.

      Another analysis examined the impact on the energy mix of assuming two-way trading plus expanded transmission capacity. For New England, greater transmission capacity allows wind, solar, and nuclear to expand further; natural gas with CCS all but disappears; and both imports and exports increase significantly. In Quebec, solar decreases still further, and both exports and imports of electricity increase.

      Those results assume that the New England power system decarbonizes by 99 percent in 2050 relative to 1990 levels. But at 90 percent and even 80 percent decarbonization levels, the model concludes that natural gas capacity decreases with the addition of new transmission relative to the current transmission scenario. Existing plants are retired, and new plants are not built as they are no longer economically justified. Since natural gas plants are the only source of carbon emissions in the 2050 energy system, the researchers conclude that the greater access to hydro reservoirs made possible by expanded transmission would accelerate the decarbonization of the electricity system.

      Effects of transmission changes on costs

      The researchers also explored how two-way trading with expanded transmission capacity would affect costs in New England and Quebec, assuming 99 percent decarbonization in New England. New England’s savings on fixed costs (investments in new equipment) are largely due to a decreased need to invest in more natural gas with CCS, and its savings on variable costs (operating costs) are due to a reduced need to run those plants. Quebec’s savings on fixed costs come from a reduced need to invest in solar generation. The increase in cost — borne by New England — reflects the construction and operation of the increased transmission capacity. The net benefit for the region is substantial.

      Thus, the analysis shows that everyone wins as transmission capacity increases — and the benefit grows as the decarbonization target tightens. At 99 percent decarbonization, the overall New England-Quebec region pays about $21 per megawatt-hour (MWh) of electricity with today’s transmission capacity but only $18/MWh with expanded transmission. Assuming 100 percent reduction in carbon emissions, the region pays $29/MWh with current transmission capacity and only $22/MWh with expanded transmission.

      Addressing misconceptions

      These results shed light on several misconceptions that policymakers, supporters of renewable energy, and others tend to have.

      The first misconception is that the New England renewables and Canadian hydropower are competitors. The modeling results instead show that they’re complementary. When the power systems in New England and Quebec work together as an integrated system, the Canadian reservoirs are used part of the time to store the renewable electricity. And with more access to hydropower storage in Quebec, there’s generally more renewable investment in New England.

      The second misconception arises when policymakers refer to Canadian hydro as a “baseload resource,” which implies a dependable source of electricity — particularly one that supplies power all the time. “Our study shows that by viewing Canadian hydropower as a baseload source of electricity — or indeed a source of electricity at all — you’re not taking full advantage of what that resource can provide,” says Dimanchev. “What we show is that Quebec’s reservoir hydro can provide storage, specifically for wind and solar. It’s a solution to the intermittency problem that we foresee in carbon-free power systems for 2050.”

      While the MIT analysis focuses on New England and Quebec, the researchers believe that their results may have wider implications. As power systems in many regions expand production of renewables, the value of storage grows. Some hydropower systems have storage capacity that has not yet been fully utilized and could be a good complement to renewable generation. Taking advantage of that capacity can lower the cost of deep decarbonization and help move some regions toward a decarbonized supply of electricity.

      This research was funded by the MIT Center for Energy and Environmental Policy Research, which is supported in part by a consortium of industry and government associates.

      This article appears in the Autumn 2021 issue of Energy Futures, the magazine of the MIT Energy Initiative. More

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      New power sources

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      In the mid-1990s, a few energy activists in Massachusetts had a vision: What if citizens had choice about the energy they consumed? Instead of being force-fed electricity sources selected by a utility company, what if cities, towns, and groups of individuals could purchase power that was cleaner and cheaper?

      The small group of activists — including a journalist, the head of a small nonprofit, a local county official, and a legislative aide — drafted model legislation along these lines that reached the state Senate in 1995. The measure stalled out. In 1997, they tried again. Massachusetts legislators were busy passing a bill to reform the state power industry in other ways, and this time the activists got their low-profile policy idea included in it — as a provision so marginal it only got a brief mention in The Boston Globe’s coverage of the bill.

      Today, this idea, often known as Community Choice Aggregation (CCA), is used by roughly 36 million people in the U.S., or 11 percent of the population. Local residents, as a bloc, purchase energy with certain specifications attached, and over 1,800 communities have adopted CCA in six states, with others testing CCA pilot programs. From such modest beginnings, CCA has become a big deal.

      “It started small, then had a profound impact,” says David Hsu, an associate professor at MIT who studies energy policy issues. Indeed, the trajectory of CCA is so striking that Hsu has researched its origins, combing through a variety of archival sources and interviewing the principals. He has now written a journal article examining the lessons and implications of this episode.

      Hsu’s paper, “Straight out of Cape Cod: The origin of community choice aggregation and its spread to other states,” appears in advance online form in the journal Energy Research and Social Science, and in the April print edition of the publication.

      “I wanted to show people that a small idea could take off into something big,” Hsu says. “For me that’s a really hopeful democratic story, where people could do something without feeling they had to take on a whole giant system that wouldn’t immediately respond to only one person.”

      Local control

      Aggregating consumers to purchase energy was not a novelty in the 1990s. Companies within many industries have long joined forces to gain purchasing power for energy. And Rhode Island tried a form of CCA slightly earlier than Massachusetts did.

      However, it is the Massachusetts model that has been adopted widely: Cities or towns can require power purchases from, say, renewable sources, while individual citizens can opt out of those agreements. More state funding (for things like efficiency improvements) is redirected to cities and towns as well.

      In both ways, CCA policies provide more local control over energy delivery. They have been adopted in California, Illinois, New Jersey, New York, and Ohio. Meanwhile, Maryland, New Hampshire, and Virginia have recently passed similar legislation (also known as municipal or government aggregation, or community choice energy).

      For cities and towns, Hsu says, “Maybe you don’t own outright the whole energy system, but let’s take away one particular function of the utility, which is procurement.”

      That vision motivated a handful of Massachusetts activists and policy experts in the 1990s, including journalist Scott Ridley, who co-wrote a 1986 book, “Power Struggle,” with the University of Massachusetts historian Richard Rudolph and had spent years thinking about ways to reconfigure the energy system; Matt Patrick, chair of a local nonprofit focused on energy efficiency; Rob O’Leary, a local official in Barnstable County, on Cape Cod; and Paul Fenn, a staff aide to the state senator who chaired the legislature’s energy committee.

      “It started with these political activists,” Hsu says.

      Hsu’s research emphasizes several lessons to be learned from the fact the legislation first failed in 1995, before unexpectedly passing in 1997. Ridley remained an author and public figure; Patrick and O’Leary would each eventually be elected to the state legislature, but only after 2000; and Fenn had left his staff position by 1995 and worked with the group long-distance from California (where he became a long-term advocate about the issue). Thus, at the time CCA passed in 1997, none of its main advocates held an insider position in state politics. How did it succeed?

      Lessons of the legislation

      In the first place, Hsu believes, a legislative process resembles what the political theorist John Kingdon has called a “multiple streams framework,” in which “many elements of the policymaking process are separate, meandering, and uncertain.” Legislation isn’t entirely controlled by big donors or other interest groups, and “policy entrepreneurs” can find success in unpredictable windows of opportunity.

      “It’s the most true-to-life theory,” says Hsu.  

      Second, Hsu emphasizes, finding allies is crucial. In the case of CCA, that came about in a few ways. Many towns in Massachusetts have a town-level legislature known as Town Meeting; the activists got those bodies in about 20 towns to pass nonbinding resolutions in favor of community choice. O’Leary helped create a regional county commission in Barnstable County, while Patrick crafted an energy plan for it. High electricity rates were affecting all of Cape Cod at the time, so community choice also served as an economic benefit for Cape Cod’s working-class service-industry employees. The activists also found that adding an opt-out clause to the 1997 version appealed to legislators, who would support CCA if their constituents were not all bound to it.

      “You really have to stick with it, and you have to look for coalition partners,” Hsu says. “It’s fun to hear them [the activists] talk about going to Town Meetings, and how they tried to build grassroots support. If you look for allies, you can get things done. [I hope] the people can see [themselves] in other people’s activism even if they’re not exactly the same as you are.”

      By 1997, the CCA legislation had more geographic support, was understood as both an economic and environmental benefit for voters, and would not force membership upon anyone. The activists, while giving media interviews, and holding conferences, had found additional traction in the principle of citizen choice.

      “It’s interesting to me how the rhetoric of [citizen] choice and the rhetoric of democracy proves to be effective,” Hsu says. “Legislators feel like they have to give everyone some choice. And it expresses a collective desire for a choice that the utilities take away by being monopolies.”

      He adds: “We need to set out principles that shape systems, rather than just taking the system as a given and trying to justify principles that are 150 years old.”

      One last element in CCA passage was good timing. The governor and legislature in Massachusetts were already seeking a “grand bargain” to restructure electricity delivery and loosen the grip of utilities; the CCA fit in as part of this larger reform movement. Still, CCA adoption has been gradual; about one-third of Massachusetts towns with CCA have only adopted it within the last five years.

      CCA’s growth does not mean it’s invulnerable to repeal or utility-funded opposition efforts — “In California there’s been pretty intense pushback,” Hsu notes. Still, Hsu concludes, the fact that a handful of activists could start a national energy-policy movement is a useful reminder that everyone’s actions can make a difference.

      “It wasn’t like they went charging through a barricade, they just found a way around it,” Hsu says. “I want my students to know you can organize and rethink the future. It takes some commitment and work over a long time.” More

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      Preparing global online learners for the clean energy transition

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      After a career devoted to making the electric power system more efficient and resilient, Marija Ilic came to MIT in 2018 eager not just to extend her research in new directions, but to prepare a new generation for the challenges of the clean-energy transition.

      To that end, Ilic, a senior research scientist in MIT’s Laboratory for Information and Decisions Systems (LIDS) and a senior staff member at Lincoln Laboratory in the Energy Systems Group, designed an edX course that captures her methods and vision: Principles of Modeling, Simulation, and Control for Electric Energy Systems.

      EdX is a provider of massive open online courses produced in partnership with MIT, Harvard University, and other leading universities. Ilic’s class made its online debut in June 2021, running for 12 weeks, and it is one of an expanding set of online courses funded by the MIT Energy Initiative (MITEI) to provide global learners with a view of the shifting energy landscape.

      Ilic first taught a version of the class while a professor at Carnegie Mellon University, rolled out a second iteration at MIT just as the pandemic struck, and then revamped the class for its current online presentation. But no matter the course location, Ilic focuses on a central theme: “With the need for decarbonization, which will mean accommodating new energy sources such as solar and wind, we must rethink how we operate power systems,” she says. “This class is about how to pose and solve the kinds of problems we will face during this transformation.”

      Hot global topic

      The edX class has been designed to welcome a broad mix of students. In summer 2021, more than 2,000 signed up from 109 countries, ranging from high school students to retirees. In surveys, some said they were drawn to the class by the opportunity to advance their knowledge of modeling. Many others hoped to learn about the move to decarbonize energy systems.

      “The energy transition is a hot topic everywhere in the world, not just in the U.S.,” says teaching assistant Miroslav Kosanic. “In the class, there were veterans of the oil industry and others working in investment and finance jobs related to energy who wanted to understand the potential impacts of changes in energy systems, as well as students from different fields and professors seeking to update their curricula — all gathered into a community.”

      Kosanic, who is currently a PhD student at MIT in electrical engineering and computer science, had taken this class remotely in the spring semester of 2021, while he was still in college in Serbia. “I knew I was interested in power systems, but this course was eye-opening for me, showing how to apply control theory and to model different components of these systems,” he says. “I finished the course and thought, this is just the beginning, and I’d like to learn a lot more.” Kosanic performed so well online that Ilic recruited him to MIT, as a LIDS researcher and edX course teaching assistant, where he grades homework assignments and moderates a lively learner community forum.

      A platform for problem-solving

      The course starts with fundamental concepts in electric power systems operations and management, and it steadily adds layers of complexity, posing real-world problems along the way. Ilic explains how voltage travels from point to point across transmission lines and how grid managers modulate systems to ensure that enough, but not too much, electricity flows. “To deliver power from one location to the next one, operators must constantly make adjustments to ensure that the receiving end can handle the voltage transmitted, optimizing voltage to avoid overheating the wires,” she says.

      In her early lectures, Ilic notes the fundamental constraints of current grid operations, organized around a hierarchy of regional managers dealing with a handful of very large oil, gas, coal, and nuclear power plants, and occupied primarily with the steady delivery of megawatt-hours to far-flung customers. But historically, this top-down structure doesn’t do a good job of preventing loss of energy due to sub-optimal transmission conditions or due to outages related to extreme weather events.

      These issues promise to grow for grid operators as distributed resources such as solar and wind enter the picture, Ilic tells students. In the United States, under new rules dictated by the Federal Energy Regulatory Commission, utilities must begin to integrate the distributed, intermittent electricity produced by wind farms, solar complexes, and even by homes and cars, which flows at voltages much lower than electricity produced by large power plants.

      Finding ways to optimize existing energy systems and to accommodate low- and zero-carbon energy sources requires powerful new modes of analysis and problem-solving. This is where Ilic’s toolbox comes in: a mathematical modeling strategy and companion software that simplifies the input and output of electrical systems, no matter how large or how small. “In the last part of the course, we take up modeling different solutions to electric service in a way that is technology-agnostic, where it only matters how much a black-box energy source produces, and the rates of production and consumption,” says Ilic.

      This black-box modeling approach, which Ilic pioneered in her research, enables students to see, for instance, “what is happening with their own household consumption, and how it affects the larger system,” says Rupamathi Jaddivada PhD ’20, a co-instructor of the edX class and a postdoc in electrical engineering and computer science. “Without getting lost in details of current or voltage, or how different components work, we think about electric energy systems as dynamical components interacting with each other, at different spatial scales.” This means that with just a basic knowledge of physical laws, high school and undergraduate students can take advantage of the course “and get excited about cleaner and more reliable energy,” adds Ilic.

      What Jaddivada and Ilic describe as “zoom in, zoom out” systems thinking leverages the ubiquity of digital communications and the so-called “internet of things.” Energy devices of all scales can link directly to other devices in a network instead of just to a central operations hub, allowing for real-time adjustments in voltage, for instance, vastly improving the potential for optimizing energy flows.

      “In the course, we discuss how information exchange will be key to integrating new end-to-end energy resources and, because of this interactivity, how we can model better ways of controlling entire energy networks,” says Ilic. “It’s a big lesson of the course to show the value of information and software in enabling us to decarbonize the system and build resilience, rather than just building hardware.”

      By the end of the course, students are invited to pursue independent research projects. Some might model the impact of a new energy source on a local grid or investigate different options for reducing energy loss in transmission lines.

      “It would be nice if they see that we don’t have to rely on hardware or large-scale solutions to bring about improved electric service and a clean and resilient grid, but instead on information technologies such as smart components exchanging data in real time, or microgrids in neighborhoods that sustain themselves even when they lose power,” says Ilic. “I hope students walk away convinced that it does make sense to rethink how we operate our basic power systems and that with systematic, physics-based modeling and IT methods we can enable better, more flexible operation in the future.”

      This article appears in the Autumn 2021 issue of Energy Futures, the magazine of the MIT Energy Initiative More

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      MIT Energy Initiative launches the Future Energy Systems Center

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      The MIT Energy Initiative (MITEI) has launched a new research consortium — the Future Energy Systems Center — to address the climate crisis and the role energy systems can play in solving it. This integrated effort engages researchers from across all of MIT to help the global community reach its goal of net-zero carbon emissions. The center examines the accelerating energy transition and collaborates with industrial leaders to reform the world’s energy systems. The center is part of “Fast Forward: MIT’s Climate Action Plan for the Decade,” MIT’s multi-pronged effort announced last year to address the climate crisis.

      The Future Energy Systems Center investigates the emerging technology, policy, demographics, and economics reshaping the landscape of energy supply and demand. The center conducts integrative analysis of the entire energy system — a holistic approach essential to understanding the cross-sectorial impact of the energy transition.

      “We must act quickly to get to net-zero greenhouse gas emissions. At the same time, we have a billion people around the world with inadequate access, or no access, to electricity — and we need to deliver it to them,” says MITEI Director Robert C. Armstrong, the Chevron Professor of Chemical Engineering. “The Future Energy Systems Center combines MIT’s deep knowledge of energy science and technology with advanced tools for systems analysis to examine how advances in technology and system economics may respond to various policy scenarios.”  

      The overarching focus of the center is integrative analysis of the entire energy system, providing insights into the complex multi-sectorial transformations needed to alter the three major energy-consuming sectors of the economy — transportation, industry, and buildings — in conjunction with three major decarbonization-enabling technologies — electricity, energy storage and low-carbon fuels, and carbon management. “Deep decarbonization of our energy system requires an economy-wide perspective on the technology options, energy flows, materials flows, life-cycle emissions, costs, policies, and socioeconomics consequences,” says Randall Field, the center’s executive director. “A systems approach is essential in enabling cross-disciplinary teams to work collaboratively together to address the existential crisis of climate change.”

      Through techno-economic and systems-oriented research, the center analyzes these important interactions. For example:

      •  Increased reliance on variable renewable energy, such as wind and solar, and greater electrification of transportation, industry, and buildings will require expansion of demand management and other solutions for balancing of electricity supply and demand across these areas.

      •  Likewise, balancing supply and demand will require deploying grid-scale energy storage and converting the electricity to low-carbon fuels (hydrogen and liquid fuels), which can in turn play a vital role in the energy transition for hard-to-decarbonize segments of transportation, industry, and buildings.

      •  Carbon management (carbon dioxide capture from industry point sources and from air and oceans; utilization/conversion to valuable products; transport; storage) will also play a critical role in decarbonizing industry, electricity, and fuels — both as carbon-mitigation and negative-carbon solutions.

      As a member-supported research consortium, the center collaborates with industrial experts and leaders — from both energy’s consumer and supplier sides — to gain insights to help researchers anticipate challenges and opportunities of deploying technology at the scale needed to achieve decarbonization. “The Future Energy Systems Center gives us a powerful way to engage with industry to accelerate the energy transition,” says Armstrong. “Working together, we can better understand how our current technology toolbox can be more effectively put to use now to reduce emissions, and what new technologies and policies will ultimately be needed to reach net-zero.”

      A steering committee, made up of 11 MIT professors and led by Armstrong, selects projects to create a research program with high impact on decarbonization, while leveraging MIT strengths and addressing interests of center members in pragmatic and scalable solutions. “MIT — through our recently released climate action plan — is committed to moving with urgency and speed to help wring carbon dioxide emissions out the global economy to resolve the growing climate crisis,” says Armstrong. “We have no time to waste.”

      The center members to date are: AECI, Analog Devices, Chevron, ConocoPhillips, Copec, Dominion, Duke Energy, Enerjisa, Eneva, Eni, Equinor, Eversource, Exelon, ExxonMobil, Ferrovial, Iberdrola, IHI, National Grid, Raizen, Repsol, Rio Tinto, Shell, Tata Power, Toyota Research Institute, and Washington Gas. More

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      Bringing climate reporting to local newsrooms

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      Last summer, Nora Hertel, a reporter for the St. Cloud Times in central Minnesota, visited a farm just northeast of the Twin Cities run by the Native American-led nonprofit Dream of Wild Health. The farm raises a mix of vegetables and flowering plants, and has a particular focus on cultivating rare heirloom varieties. It’s also dealing with severely depleted soil, inherited from previous owners who grew corn on the same land. Hertel had come to learn about the techniques the farm was using to restore its soil, many of which were traditional parts of Indigenous farming practice, including planting cover crops over the winter and incorporating burnt wood and manure into the earth.

      The trip was part of a multi-part reporting project that Hertel undertook as an inaugural fellow in a new program from the MIT Environmental Solutions Initiative (ESI). The ESI Journalism Fellowship was created to help local reporters around the United States connect climate change science and solutions with issues that are already of importance to their audiences — particularly in areas where many people are still unclear or unsure about climate change. For Hertel, that meant visiting 10 farms and forest lands across Minnesota to understand how natural climate solutions are taking shape in her state. The practices she saw at the Dream of Wild Health farm not only helped to restore soil, but also helped slow climate change by taking carbon dioxide out of the air and storing it in soils and plants.

      “There is enthusiasm for natural climate solutions,” Hertel says, but these practices can be expensive and difficult to adopt. She wanted to explain the benefits and the hurdles, especially for farmers and land managers considering new agricultural techniques.

      Hertel produced six news pieces for the St. Cloud Times as part of her project, as well as a six-episode podcast series and two videos. To conclude the series, she ran a public event where 130 attendees — including conventional farmers, regenerative farmers, state senators, the St. Cloud mayor, and other community stakeholders — gathered outside in the 40-degree Fahrenheit cold to discuss carbon markets in Minnesota. The stories were republished in 12 additional outlets, including USA Today, Associated Press, Yahoo News, and US News & World Report. 

      “I had been hoping to write about cover crops and carbon markets for about two years before I pitched my project to ESI,” says Hertel. “I hadn’t been able to take the time and resources with all my other responsibilities. Joining the fellowship allowed me to focus on those topics and dive in deep to understand how much is uncertain and changing in the field right now.”

      Supporting local climate reporting

      In today’s news landscape, local coverage is dwindling, which has major effects on the ways people hear about climate change. At times, the only in-depth climate coverage available is covered by specialty or national publications, which can miss the opportunity to understand the nuances of the communities they are parachuting into.

      “Climate change is or will impact all of us, but many Americans don’t see it as relevant to their lives,” says Laur Hesse Fisher, program director at the ESI, who created and manages the fellowship program. “We’re working to help change that.”

      In this first year of the fellowship, five local journalists were selected from around the country to pursue long-form or serial climate-focused reporting. Fellows received funding and stipends to help them dedicate extra time and resources to their projects. They gathered virtually for workshops and were connected with MIT experts in a variety of relevant fields: scientists such as Adam Schlosser, senior research scientist and deputy director for science research at the MIT Joint Program on the Science and Policy of Global Change; economists and policy experts such as Joshua Hodge, executive director of the MIT Center for Energy and Environmental Policy Research (CEEPR); and journalism experts from the MIT Knight Science Journalism Program.

      Fellows were also given full access to MIT’s extensive library databases and geographic data visualization tools, along with tools focused specifically on climate science and policy like the MIT Socio-Environmental Triage platform and CEEPR’s working papers. All these resources aimed to give the journalism fellows the backing they needed to undertake ambitious projects on climate issues their audiences might otherwise never have known were playing out right in their backyards.

      Stories around the country

      The result was five distinct reporting projects spread across the United States.

      ESI Fellow Tristan Baurick is an environment reporter for the Times Picayune | New Orleans Advocate, Louisiana’s largest newspaper. His multi-part series, “Wind of Change: How the Gulf of Mexico could be the next offshore wind powerhouse,” ran on the front page of the Thanksgiving print edition of the paper. It explores how the state’s offshore oil companies are pivoting to support the emerging wind energy industry, as well as the outcomes of the U.S.’s first offshore wind farm in Rhode Island, which Baurick visited on an extended reporting trip. The series looks at the history of Louisiana, which, despite being a hub for wind engineering technology production, has seen most of that technology exported. “The project relied on experts from the oil and gas industry to introduce the idea of offshore wind energy and the opportunities it could offer the region,” says Baurick. “This approach made readers who are skeptical of climate change and renewable energy let their guard down and consider these topics with a more open mind.”

      Oregon-based environmental journalist Alex Schwartz explored water rights and climate change within the Klamath River Basin for the Herald & News. The result was a five-part digital series that examines the many stakeholders, including Indigenous groups, farmers, fishers, and park managers, who depend on the Klamath River for water even as the region enters a period of extended climate change-induced drought. “The fellowship provided me with financial resources to be able to execute a project at this scale,” says Schwartz. “We never would have been able to take the time off and travel throughout the basin without the support of the fellowship.”

      Melba Newsome is a North Carolina-based independent reporter. Her two-part series for NC Health News focuses on Smithfield’s Foods, whose hog houses continue to have lasting health and environmental implications for majority Black communities in the southeastern part of the state. The series, which has been republished by Indy Weekly, the Daily Yonder, and others, interviews residents and activists to untangle a history of legal battles, neglect, and accusations of environmental racism — while noting that sea-level rise has made the region increasingly vulnerable to dangerous releases of waste from its growing factory farms.

      The final project supported by the fellowship came from Wyoming, famous for its vast outdoors and coal industry. In his three-part series for WyoFile, journalist Dustin Bleizeffer — whose beat shifted from education to energy and climate in part as a result of his fellowship — spoke to local residents to capture their personal experiences of warming temperatures and changing landscapes. “[Of] the people I interviewed and featured in my reporting … all but one are climate skeptics, but they spoke in detail about climate changes they’ve observed, and very eloquently described their concerns,” says Bleizeffer. “I’m still receiving comments and enthusiasm to keep the conversation going.” He also looked at how two Wyoming counties, Gillette and Campbell, are faring through the coal industry’s decline. His series provided a boost to efforts by grassroots organizations and conservation groups that are trying to open “the climate conversation” in the state.

      Lessons for climate conversations

      All five fellows joined ESI for a wrap-up event on Nov. 4, Connecting with Americans on Climate Change, which both showcased their work and gave them the opportunity to publicly discuss ways to engage Americans across the political spectrum on climate change.

      The event was joined by sociologist Arlie Russell Hochschild, author of the bestselling “Strangers in Their Own Land: Anger and Mourning on the American Right,” who had earlier joined the fellows in one of their workshops to offer her own experience engaging with people who feel ill-served by the national media. Her book, which followed members of the Tea Party in Louisiana for five years, illustrates the importance of deep listening to bridging America’s social and political divides. Hochschild applied this insight to climate change in talking with the fellows and event attendees about strategies to understand and respond to local perspectives on what is often framed as a contentious political issue. “Sociology gives us forgiveness; [it] gets blame and guilt out of the picture,” said Hochschild.

      That was an insight echoed by several of the journalism fellows. “I think rural people feel blamed a lot for every problem,” said Schwartz. “If we were to take the carbon footprint of the Klamath River Basin, it would be minuscule compared to any corporation, right? … We have to create that safety net for our communities to be able to bear the brunt of these cascading disasters that are already occurring and are just going to get worse in the future. Focusing on the adaptation side was really helpful in terms of just getting people to talk about climate change.”

      Other fellows had their own strategies for opening conversations about climate change — and by responding to their audiences’ concerns, they did see opportunities for change in their reporting. In Wyoming, Bleizeffer talked about the need to retain young people in the state, and about changes to landscapes residents loved. Newsome emphasized that people need to see climate change as not someone else’s problem — for her audience, it illustrated and exacerbated injustices they were already feeling.

      And Hertel, speaking of the conventional farmers, everyday people, and local government officials featured in her series, left event attendees with one more insight about effective climate reporting. “Don’t expect people to change on a dime,” she said. “You must bring people [along] on the journey.”

      ESI will be opening journalism fellowship applications for its second cohort later this year. Experienced reporters are encouraged to apply. If you are interested in supporting this fellowship or are curious about opportunities for partnerships, please contact Laur Hesse Fisher. More

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      An energy-storage solution that flows like soft-serve ice cream

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      Batteries made from an electrically conductive mixture the consistency of molasses could help solve a critical piece of the decarbonization puzzle. An interdisciplinary team from MIT has found that an electrochemical technology called a semisolid flow battery can be a cost-competitive form of energy storage and backup for variable renewable energy (VRE) sources such as wind and solar. The group’s research is described in a paper published in Joule.

      “The transition to clean energy requires energy storage systems of different durations for when the sun isn’t shining and the wind isn’t blowing,” says Emre Gençer, a research scientist with the MIT Energy Initiative (MITEI) and a member of the team. “Our work demonstrates that a semisolid flow battery could be a lifesaving as well as economical option when these VRE sources can’t generate power for a day or longer — in the case of natural disasters, for instance.”

      The rechargeable zinc-manganese dioxide (Zn-MnO2) battery the researchers created beat out other long-duration energy storage contenders. “We performed a comprehensive, bottom-up analysis to understand how the battery’s composition affects performance and cost, looking at all the trade-offs,” says Thaneer Malai Narayanan SM ’18, PhD ’21. “We showed that our system can be cheaper than others, and can be scaled up.”

      Narayanan, who conducted this work at MIT as part of his doctorate in mechanical engineering, is the lead author of the paper. Additional authors include Gençer, Yunguang Zhu, a postdoc in the MIT Electrochemical Energy Lab; Gareth McKinley, the School of Engineering Professor of Teaching Innovation and professor of mechanical engineering at MIT; and Yang Shao-Horn, the JR East Professor of Engineering, a professor of mechanical engineering and of materials science and engineering, and a member of the Research Laboratory of Electronics (RLE), who directs the MIT Electrochemical Energy Lab.

      Going with the flow

      In 2016, Narayanan began his graduate studies, joining the Electrochemical Energy Lab, a hotbed of research and exploration of solutions to mitigate climate change, which is centered on innovative battery chemistry and decarbonizing fuels and chemicals. One exciting opportunity for the lab: developing low- and no-carbon backup energy systems suitable for grid-scale needs when VRE generation flags.                                                  

      While the lab cast a wide net, investigating energy conversion and storage using solid oxide fuel cells, lithium-ion batteries, and metal-air batteries, among others, Narayanan took a particular interest in flow batteries. In these systems, two different chemical (electrolyte) solutions with either negative or positive ions are pumped from separate tanks, meeting across a membrane (called the stack). Here, the ion streams react, converting electrical energy to chemical energy — in effect, charging the battery. When there is demand for this stored energy, the solution gets pumped back to the stack to convert chemical energy into electrical energy again.

      The duration of time that flow batteries can discharge, releasing the stored electricity, is determined by the volume of positively and negatively charged electrolyte solutions streaming through the stack. In theory, as long as these solutions keep flowing, reacting, and converting the chemical energy to electrical energy, the battery systems can provide electricity.

      “For backup lasting more than a day, the architecture of flow batteries suggests they can be a cheap option,” says Narayanan. “You recharge the solution in the tanks from sun and wind power sources.” This renders the entire system carbon free.

      But while the promise of flow battery technologies has beckoned for at least a decade, the uneven performance and expense of materials required for these battery systems has slowed their implementation. So, Narayanan set out on an ambitious journey: to design and build a flow battery that could back up VRE systems for a day or more, storing and discharging energy with the same or greater efficiency than backup rivals; and to determine, through rigorous cost analysis, whether such a system could prove economically viable as a long-duration energy option.

      Multidisciplinary collaborators

      To attack this multipronged challenge, Narayanan’s project brought together, in his words, “three giants, scientists all well-known in their fields”:  Shao-Horn, who specializes in chemical physics and electrochemical science, and design of materials; Gençer, who creates detailed economic models of emergent energy systems at MITEI; and McKinley, an expert in rheology, the physics of flow. These three also served as his thesis advisors.

      “I was excited to work in such an interdisciplinary team, which offered a unique opportunity to create a novel battery architecture by designing charge transfer and ion transport within flowable semi-solid electrodes, and to guide battery engineering using techno-economics of such flowable batteries,” says Shao-Horn.

      While other flow battery systems in contention, such as the vanadium redox flow battery, offer the storage capacity and energy density to back up megawatt and larger power systems, they depend on expensive chemical ingredients that make them bad bets for long duration purposes. Narayanan was on the hunt for less-pricey chemical components that also feature rich energy potential.

      Through a series of bench experiments, the researchers came up with a novel electrode (electrical conductor) for the battery system: a mixture containing dispersed manganese dioxide (MnO2) particles, shot through with an electrically conductive additive, carbon black. This compound reacts with a conductive zinc solution or zinc plate at the stack, enabling efficient electrochemical energy conversion. The fluid properties of this battery are far removed from the watery solutions used by other flow batteries.

      “It’s a semisolid — a slurry,” says Narayanan. “Like thick, black paint, or perhaps a soft-serve ice cream,” suggests McKinley. The carbon black adds the pigment and the electric punch. To arrive at the optimal electrochemical mix, the researchers tweaked their formula many times.

      “These systems have to be able to flow under reasonable pressures, but also have a weak yield stress so that the active MnO2 particles don’t sink to the bottom of the flow tanks when the system isn’t being used, as well as not separate into a battery/oily clear fluid phase and a dense paste of carbon particles and MnO2,” says McKinley.

      This series of experiments informed the technoeconomic analysis. By “connecting the dots between composition, performance, and cost,” says Narayanan, he and Gençer were able to make system-level cost and efficiency calculations for the Zn-MnO2 battery.

      “Assessing the cost and performance of early technologies is very difficult, and this was an example of how to develop a standard method to help researchers at MIT and elsewhere,” says Gençer. “One message here is that when you include the cost analysis at the development stage of your experimental work, you get an important early understanding of your project’s cost implications.”

      In their final round of studies, Gençer and Narayanan compared the Zn-MnO2 battery to a set of equivalent electrochemical battery and hydrogen backup systems, looking at the capital costs of running them at durations of eight, 24, and 72 hours. Their findings surprised them: For battery discharges longer than a day, their semisolid flow battery beat out lithium-ion batteries and vanadium redox flow batteries. This was true even when factoring in the heavy expense of pumping the MnO2 slurry from tank to stack. “I was skeptical, and not expecting this battery would be competitive, but once I did the cost calculation, it was plausible,” says Gençer.

      But carbon-free battery backup is a very Goldilocks-like business: Different situations require different-duration solutions, whether an anticipated overnight loss of solar power, or a longer-term, climate-based disruption in the grid. “Lithium-ion is great for backup of eight hours and under, but the materials are too expensive for longer periods,” says Gençer. “Hydrogen is super expensive for very short durations, and good for very long durations, and we will need all of them.” This means it makes sense to continue working on the Zn-MnO2 system to see where it might fit in.

      “The next step is to take our battery system and build it up,” says Narayanan, who is working now as a battery engineer. “Our research also points the way to other chemistries that could be developed under the semi-solid flow battery platform, so we could be seeing this kind of technology used for energy storage in our lifetimes.”

      This research was supported by Eni S.p.A. through MITEI. Thaneer Malai Narayanan received an Eni-sponsored MIT Energy Fellowship during his work on the project. More