Energy storage

Subterms

    More stories

    • 113 Shares199 Views

      in Energy

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

      by

      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

    • 75 Shares129 Views

      in Energy

      Energy storage from a chemistry perspective

      by

      The transition toward a more sustainable, environmentally sound electrical grid has driven an upsurge in renewables like solar and wind. But something as simple as cloud cover can cause grid instability, and wind power is inherently unpredictable. This intermittent nature of renewables has invigorated the competitive landscape for energy storage companies looking to enhance power system flexibility while enabling the integration of renewables.

      “Impact is what drives PolyJoule more than anything else,” says CEO Eli Paster. “We see impact from a renewable integration standpoint, from a curtailment standpoint, and also from the standpoint of transitioning from a centralized to a decentralized model of energy-power delivery.”

      PolyJoule is a Billerica, Massachusetts-based startup that’s looking to reinvent energy storage from a chemistry perspective. Co-founders Ian Hunter of MIT’s Department of Mechanical Engineering and Tim Swager of the Department of Chemistry are longstanding MIT professors considered luminaries in their respective fields. Meanwhile, the core team is a small but highly skilled collection of chemists, manufacturing specialists, supply chain optimizers, and entrepreneurs, many of whom have called MIT home at one point or another.

      “The ideas that we work on in the lab, you’ll see turned into products three to four years from now, and they will still be innovative and well ahead of the curve when they get to market,” Paster says. “But the concepts come from the foresight of thinking five to 10 years in advance. That’s what we have in our back pocket, thanks to great minds like Ian and Tim.”

      PolyJoule takes a systems-level approach married to high-throughput, analytical electrochemistry that has allowed the company to pinpoint a chemical cell design based on 10,000 trials. The result is a battery that is low-cost, safe, and has a long lifetime. It’s capable of responding to base loads and peak loads in microseconds, allowing the same battery to participate in multiple power markets and deployment use cases.

      In the energy storage sphere, interesting technologies abound, but workable solutions are few and far between. But Paster says PolyJoule has managed to bridge the gap between the lab and the real world by taking industry concerns into account from the beginning. “We’ve taken a slightly contrarian view to all of the other energy storage companies that have come before us that have said, ‘If we build it, they will come.’ Instead, we’ve gone directly to the customer and asked, ‘If you could have a better battery storage platform, what would it look like?’”

      With commercial input feeding into the thought processes behind their technological and commercial deployment, PolyJoule says they’ve designed a battery that is less expensive to make, less expensive to operate, safer, and easier to deploy.

      Traditionally, lithium-ion batteries have been the go-to energy storage solution. But lithium has its drawbacks, including cost, safety issues, and detrimental effects on the environment. But PolyJoule isn’t interested in lithium — or metals of any kind, in fact. “We start with the periodic table of organic elements,” says Paster, “and from there, we derive what works at economies of scale, what is easy to converge and convert chemically.”

      Having an inherently safer chemistry allows PolyJoule to save on system integration costs, among other things. PolyJoule batteries don’t contain flammable solvents, which means no added expenses related to fire mitigation. Safer chemistry also means ease of storage, and PolyJoule batteries are currently undergoing global safety certification (UL approval) to be allowed indoors and on airplanes. Finally, with high power built into the chemistry, PolyJoule’s cells can be charged and discharged to extremes, without the need for heating or cooling systems.

      “From raw material to product delivery, we examine each step in the value chain with an eye towards reducing costs,” says Paster. It all starts with designing the chemistry around earth-abundant elements, which allows the small startup to compete with larger suppliers, even at smaller scales. Consider the fact that PolyJoule’s differentiating material cost is less than $1 per kilogram, whereas lithium carbonate sells for $20 per kilogram.

      On the manufacturing side, Paster explains that PolyJoule cuts costs by making their cells in old paper mills and warehouses, employing off-the-shelf equipment previously used for tissue paper or newspaper printing. “We use equipment that has been around for decades because we don’t want to create a cutting-edge technology that requires cutting-edge manufacturing,” he says. “We want to create a cutting-edge technology that can be deployed in industrialized nations and in other nations that can benefit the most from energy storage.”

      PolyJoule’s first customer is an industrial distributed energy consumer with baseline energy consumption that increases by a factor of 10 when the heavy machinery kicks on twice a day. In the early morning and late afternoon, it consumes about 50 kilowatts for 20 minutes to an hour, compared to a baseline rate of 5  kilowatts. It’s an application model that is translatable to a variety of industries. Think wastewater treatment, food processing, and server farms — anything with a fluctuation in power consumption over a 24-hour period.

      By the end of the year, PolyJoule will have delivered its first 10 kilowatt-hour system, exiting stealth mode and adding commercial viability to demonstrated technological superiority. “What we’re seeing, now is massive amounts of energy storage being added to renewables and grid-edge applications,” says Paster. “We anticipated that by 12-18 months, and now we’re ramping up to catch up with some of the bigger players.” More

    • 75 Shares159 Views

      in Energy

      Designing better batteries for electric vehicles

      by

      The urgent need to cut carbon emissions is prompting a rapid move toward electrified mobility and expanded deployment of solar and wind on the electric grid. If those trends escalate as expected, the need for better methods of storing electrical energy will intensify.

      “We need all the strategies we can get to address the threat of climate change,” says Elsa Olivetti PhD ’07, the Esther and Harold E. Edgerton Associate Professor in Materials Science and Engineering. “Obviously, developing technologies for grid-based storage at a large scale is critical. But for mobile applications — in particular, transportation — much research is focusing on adapting today’s lithium-ion battery to make versions that are safer, smaller, and can store more energy for their size and weight.”

      Traditional lithium-ion batteries continue to improve, but they have limitations that persist, in part because of their structure. A lithium-ion battery consists of two electrodes — one positive and one negative — sandwiched around an organic (carbon-containing) liquid. As the battery is charged and discharged, electrically charged particles (or ions) of lithium pass from one electrode to the other through the liquid electrolyte.

      One problem with that design is that at certain voltages and temperatures, the liquid electrolyte can become volatile and catch fire. “Batteries are generally safe under normal usage, but the risk is still there,” says Kevin Huang PhD ’15, a research scientist in Olivetti’s group.

      Another problem is that lithium-ion batteries are not well-suited for use in vehicles. Large, heavy battery packs take up space and increase a vehicle’s overall weight, reducing fuel efficiency. But it’s proving difficult to make today’s lithium-ion batteries smaller and lighter while maintaining their energy density — that is, the amount of energy they store per gram of weight.

      To solve those problems, researchers are changing key features of the lithium-ion battery to make an all-solid, or “solid-state,” version. They replace the liquid electrolyte in the middle with a thin, solid electrolyte that’s stable at a wide range of voltages and temperatures. With that solid electrolyte, they use a high-capacity positive electrode and a high-capacity, lithium metal negative electrode that’s far thinner than the usual layer of porous carbon. Those changes make it possible to shrink the overall battery considerably while maintaining its energy-storage capacity, thereby achieving a higher energy density.

      “Those features — enhanced safety and greater energy density — are probably the two most-often-touted advantages of a potential solid-state battery,” says Huang. He then quickly clarifies that “all of these things are prospective, hoped-for, and not necessarily realized.” Nevertheless, the possibility has many researchers scrambling to find materials and designs that can deliver on that promise.

      Thinking beyond the lab

      Researchers have come up with many intriguing options that look promising — in the lab. But Olivetti and Huang believe that additional practical considerations may be important, given the urgency of the climate change challenge. “There are always metrics that we researchers use in the lab to evaluate possible materials and processes,” says Olivetti. Examples might include energy-storage capacity and charge/discharge rate. When performing basic research — which she deems both necessary and important — those metrics are appropriate. “But if the aim is implementation, we suggest adding a few metrics that specifically address the potential for rapid scaling,” she says.

      Based on industry’s experience with current lithium-ion batteries, the MIT researchers and their colleague Gerbrand Ceder, the Daniel M. Tellep Distinguished Professor of Engineering at the University of California at Berkeley, suggest three broad questions that can help identify potential constraints on future scale-up as a result of materials selection. First, with this battery design, could materials availability, supply chains, or price volatility become a problem as production scales up? (Note that the environmental and other concerns raised by expanded mining are outside the scope of this study.) Second, will fabricating batteries from these materials involve difficult manufacturing steps during which parts are likely to fail? And third, do manufacturing measures needed to ensure a high-performance product based on these materials ultimately lower or raise the cost of the batteries produced?

      To demonstrate their approach, Olivetti, Ceder, and Huang examined some of the electrolyte chemistries and battery structures now being investigated by researchers. To select their examples, they turned to previous work in which they and their collaborators used text- and data-mining techniques to gather information on materials and processing details reported in the literature. From that database, they selected a few frequently reported options that represent a range of possibilities.

      Materials and availability

      In the world of solid inorganic electrolytes, there are two main classes of materials — the oxides, which contain oxygen, and the sulfides, which contain sulfur. Olivetti, Ceder, and Huang focused on one promising electrolyte option in each class and examined key elements of concern for each of them.

      The sulfide they considered was LGPS, which combines lithium, germanium, phosphorus, and sulfur. Based on availability considerations, they focused on the germanium, an element that raises concerns in part because it’s not generally mined on its own. Instead, it’s a byproduct produced during the mining of coal and zinc.

      To investigate its availability, the researchers looked at how much germanium was produced annually in the past six decades during coal and zinc mining and then at how much could have been produced. The outcome suggested that 100 times more germanium could have been produced, even in recent years. Given that supply potential, the availability of germanium is not likely to constrain the scale-up of a solid-state battery based on an LGPS electrolyte.

      The situation looked less promising with the researchers’ selected oxide, LLZO, which consists of lithium, lanthanum, zirconium, and oxygen. Extraction and processing of lanthanum are largely concentrated in China, and there’s limited data available, so the researchers didn’t try to analyze its availability. The other three elements are abundantly available. However, in practice, a small quantity of another element — called a dopant — must be added to make LLZO easy to process. So the team focused on tantalum, the most frequently used dopant, as the main element of concern for LLZO.

      Tantalum is produced as a byproduct of tin and niobium mining. Historical data show that the amount of tantalum produced during tin and niobium mining was much closer to the potential maximum than was the case with germanium. So the availability of tantalum is more of a concern for the possible scale-up of an LLZO-based battery.

      But knowing the availability of an element in the ground doesn’t address the steps required to get it to a manufacturer. So the researchers investigated a follow-on question concerning the supply chains for critical elements — mining, processing, refining, shipping, and so on. Assuming that abundant supplies are available, can the supply chains that deliver those materials expand quickly enough to meet the growing demand for batteries?

      In sample analyses, they looked at how much supply chains for germanium and tantalum would need to grow year to year to provide batteries for a projected fleet of electric vehicles in 2030. As an example, an electric vehicle fleet often cited as a goal for 2030 would require production of enough batteries to deliver a total of 100 gigawatt hours of energy. To meet that goal using just LGPS batteries, the supply chain for germanium would need to grow by 50 percent from year to year — a stretch, since the maximum growth rate in the past has been about 7 percent. Using just LLZO batteries, the supply chain for tantalum would need to grow by about 30 percent — a growth rate well above the historical high of about 10 percent.

      Those examples demonstrate the importance of considering both materials availability and supply chains when evaluating different solid electrolytes for their scale-up potential. “Even when the quantity of a material available isn’t a concern, as is the case with germanium, scaling all the steps in the supply chain to match the future production of electric vehicles may require a growth rate that’s literally unprecedented,” says Huang.

      Materials and processing

      In assessing the potential for scale-up of a battery design, another factor to consider is the difficulty of the manufacturing process and how it may impact cost. Fabricating a solid-state battery inevitably involves many steps, and a failure at any step raises the cost of each battery successfully produced. As Huang explains, “You’re not shipping those failed batteries; you’re throwing them away. But you’ve still spent money on the materials and time and processing.”

      As a proxy for manufacturing difficulty, Olivetti, Ceder, and Huang explored the impact of failure rate on overall cost for selected solid-state battery designs in their database. In one example, they focused on the oxide LLZO. LLZO is extremely brittle, and at the high temperatures involved in manufacturing, a large sheet that’s thin enough to use in a high-performance solid-state battery is likely to crack or warp.

      To determine the impact of such failures on cost, they modeled four key processing steps in assembling LLZO-based batteries. At each step, they calculated cost based on an assumed yield — that is, the fraction of total units that were successfully processed without failing. With the LLZO, the yield was far lower than with the other designs they examined; and, as the yield went down, the cost of each kilowatt-hour (kWh) of battery energy went up significantly. For example, when 5 percent more units failed during the final cathode heating step, cost increased by about $30/kWh — a nontrivial change considering that a commonly accepted target cost for such batteries is $100/kWh. Clearly, manufacturing difficulties can have a profound impact on the viability of a design for large-scale adoption.

      Materials and performance

      One of the main challenges in designing an all-solid battery comes from “interfaces” — that is, where one component meets another. During manufacturing or operation, materials at those interfaces can become unstable. “Atoms start going places that they shouldn’t, and battery performance declines,” says Huang.

      As a result, much research is devoted to coming up with methods of stabilizing interfaces in different battery designs. Many of the methods proposed do increase performance; and as a result, the cost of the battery in dollars per kWh goes down. But implementing such solutions generally involves added materials and time, increasing the cost per kWh during large-scale manufacturing.

      To illustrate that trade-off, the researchers first examined their oxide, LLZO. Here, the goal is to stabilize the interface between the LLZO electrolyte and the negative electrode by inserting a thin layer of tin between the two. They analyzed the impacts — both positive and negative — on cost of implementing that solution. They found that adding the tin separator increases energy-storage capacity and improves performance, which reduces the unit cost in dollars/kWh. But the cost of including the tin layer exceeds the savings so that the final cost is higher than the original cost.

      In another analysis, they looked at a sulfide electrolyte called LPSCl, which consists of lithium, phosphorus, and sulfur with a bit of added chlorine. In this case, the positive electrode incorporates particles of the electrolyte material — a method of ensuring that the lithium ions can find a pathway through the electrolyte to the other electrode. However, the added electrolyte particles are not compatible with other particles in the positive electrode — another interface problem. In this case, a standard solution is to add a “binder,” another material that makes the particles stick together.

      Their analysis confirmed that without the binder, performance is poor, and the cost of the LPSCl-based battery is more than $500/kWh. Adding the binder improves performance significantly, and the cost drops by almost $300/kWh. In this case, the cost of adding the binder during manufacturing is so low that essentially all the of the cost decrease from adding the binder is realized. Here, the method implemented to solve the interface problem pays off in lower costs.

      The researchers performed similar studies of other promising solid-state batteries reported in the literature, and their results were consistent: The choice of battery materials and processes can affect not only near-term outcomes in the lab but also the feasibility and cost of manufacturing the proposed solid-state battery at the scale needed to meet future demand. The results also showed that considering all three factors together — availability, processing needs, and battery performance — is important because there may be collective effects and trade-offs involved.

      Olivetti is proud of the range of concerns the team’s approach can probe. But she stresses that it’s not meant to replace traditional metrics used to guide materials and processing choices in the lab. “Instead, it’s meant to complement those metrics by also looking broadly at the sorts of things that could get in the way of scaling” — an important consideration given what Huang calls “the urgent ticking clock” of clean energy and climate change.

      This research was supported by the Seed Fund Program of the MIT Energy Initiative (MITEI) Low-Carbon Energy Center for Energy Storage; by Shell, a founding member of MITEI; and by the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy, Vehicle Technologies Office, under the Advanced Battery Materials Research Program. The text mining work was supported by the National Science Foundation, the Office of Naval Research, and MITEI.

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

    • 125 Shares199 Views

      in Environment

      What will happen to sediment plumes associated with deep-sea mining?

      by

      In certain parts of the deep ocean, scattered across the seafloor, lie baseball-sized rocks layered with minerals accumulated over millions of years. A region of the central Pacific, called the Clarion Clipperton Fracture Zone (CCFZ), is estimated to contain vast reserves of these rocks, known as “polymetallic nodules,” that are rich in nickel and cobalt  — minerals that are commonly mined on land for the production of lithium-ion batteries in electric vehicles, laptops, and mobile phones.

      As demand for these batteries rises, efforts are moving forward to mine the ocean for these mineral-rich nodules. Such deep-sea-mining schemes propose sending down tractor-sized vehicles to vacuum up nodules and send them to the surface, where a ship would clean them and discharge any unwanted sediment back into the ocean. But the impacts of deep-sea mining — such as the effect of discharged sediment on marine ecosystems and how these impacts compare to traditional land-based mining — are currently unknown.

      Now oceanographers at MIT, the Scripps Institution of Oceanography, and elsewhere have carried out an experiment at sea for the first time to study the turbulent sediment plume that mining vessels would potentially release back into the ocean. Based on their observations, they developed a model that makes realistic predictions of how a sediment plume generated by mining operations would be transported through the ocean.

      The model predicts the size, concentration, and evolution of sediment plumes under various marine and mining conditions. These predictions, the researchers say, can now be used by biologists and environmental regulators to gauge whether and to what extent such plumes would impact surrounding sea life.

      “There is a lot of speculation about [deep-sea-mining’s] environmental impact,” says Thomas Peacock, professor of mechanical engineering at MIT. “Our study is the first of its kind on these midwater plumes, and can be a major contributor to international discussion and the development of regulations over the next two years.”

      The team’s study appears today in Nature Communications: Earth and Environment.

      Peacock’s co-authors at MIT include lead author Carlos Muñoz-Royo, Raphael Ouillon, Chinmay Kulkarni, Patrick Haley, Chris Mirabito, Rohit Supekar, Andrew Rzeznik, Eric Adams, Cindy Wang, and Pierre Lermusiaux, along with collaborators at Scripps, the U.S. Geological Survey, and researchers in Belgium and South Korea.

      Play video

      Out to sea

      Current deep-sea-mining proposals are expected to generate two types of sediment plumes in the ocean: “collector plumes” that vehicles generate on the seafloor as they drive around collecting nodules 4,500 meters below the surface; and possibly “midwater plumes” that are discharged through pipes that descend 1,000 meters or more into the ocean’s aphotic zone, where sunlight rarely penetrates.

      In their new study, Peacock and his colleagues focused on the midwater plume and how the sediment would disperse once discharged from a pipe.

      “The science of the plume dynamics for this scenario is well-founded, and our goal was to clearly establish the dynamic regime for such plumes to properly inform discussions,” says Peacock, who is the director of MIT’s Environmental Dynamics Laboratory.

      To pin down these dynamics, the team went out to sea. In 2018, the researchers boarded the research vessel Sally Ride and set sail 50 kilometers off the coast of Southern California. They brought with them equipment designed to discharge sediment 60 meters below the ocean’s surface.  

      “Using foundational scientific principles from fluid dynamics, we designed the system so that it fully reproduced a commercial-scale plume, without having to go down to 1,000 meters or sail out several days to the middle of the CCFZ,” Peacock says.

      Over one week the team ran a total of six plume experiments, using novel sensors systems such as a Phased Array Doppler Sonar (PADS) and epsilometer developed by Scripps scientists to monitor where the plumes traveled and how they evolved in shape and concentration. The collected data revealed that the sediment, when initially pumped out of a pipe, was a highly turbulent cloud of suspended particles that mixed rapidly with the surrounding ocean water.

      “There was speculation this sediment would form large aggregates in the plume that would settle relatively quickly to the deep ocean,” Peacock says. “But we found the discharge is so turbulent that it breaks the sediment up into its finest constituent pieces, and thereafter it becomes dilute so quickly that the sediment then doesn’t have a chance to stick together.”

      Dilution

      The team had previously developed a model to predict the dynamics of a plume that would be discharged into the ocean. When they fed the experiment’s initial conditions into the model, it produced the same behavior that the team observed at sea, proving the model could accurately predict plume dynamics within the vicinity of the discharge.

      The researchers used these results to provide the correct input for simulations of ocean dynamics to see how far currents would carry the initially released plume.

      “In a commercial operation, the ship is always discharging new sediment. But at the same time the background turbulence of the ocean is always mixing things. So you reach a balance. There’s a natural dilution process that occurs in the ocean that sets the scale of these plumes,” Peacock says. “What is key to determining the extent of the plumes is the strength of the ocean turbulence, the amount of sediment that gets discharged, and the environmental threshold level at which there is impact.”

      Based on their findings, the researchers have developed formulae to calculate the scale of a plume depending on a given environmental threshold. For instance, if regulators determine that a certain concentration of sediments could be detrimental to surrounding sea life, the formula can be used to calculate how far a plume above that concentration would extend, and what volume of ocean water would be impacted over the course of a 20-year nodule mining operation.

      “At the heart of the environmental question surrounding deep-sea mining is the extent of sediment plumes,” Peacock says. “It’s a multiscale problem, from micron-scale sediments, to turbulent flows, to ocean currents over thousands of kilometers. It’s a big jigsaw puzzle, and we are uniquely equipped to work on that problem and provide answers founded in science and data.”

      The team is now working on collector plumes, having recently returned from several weeks at sea to perform the first environmental monitoring of a nodule collector vehicle in the deep ocean in over 40 years.

      This research was supported in part by the MIT Environmental Solutions Initiative, the UC Ship Time Program, the MIT Policy Lab, the 11th Hour Project of the Schmidt Family Foundation, the Benioff Ocean Initiative, and Fundación Bancaria “la Caixa.” More