Established electric grids currently face several challenges. While they are reliable, the infrastructure continues to age. They are also inefficient, designed for peak capacity, so that the actual utilisation rate is typically well below 50%. Furthermore, they are not designed for integrating intermittent renewable energy sources and the mismatch of supply and demand. With the additional unplanned closure of nuclear reactors and coal-fired power plants around the world, there is an immediate need for alternative sources of power. Chemical batteries may provide the answer.
Most energy storage on the grid today is in the form of pumped hydro, with a small amount of underground compressed air storage. ‘There is 100 times as much pumped hydro in megawatts (MW) as there is for all battery technologies put together,’ says Haresh Kamath, program manager for energy storage at the Electric Power Research Institute (EPRI) in the US. These systems, however, often cannot be located near the site of consumption and available locations are increasingly limited.
The potential benefit of batteries becomes obvious. They can be rapidly installed, scaled to size over time and sited in sensitive areas as needed. ‘Today, utilities and their regulators are increasingly hesitant to authorise large infrastructure upgrades given the asset risks associated with uncertainties in customer demand and technology development. Storage is therefore starting to become a cost-effective alternative for providing peak period reliability without committing to a 30-year investment,’ asserts Johannes Rittershausen, md of Convergent Energy + Power, US. He also notes that the need for alternatives to replace the retiring coal capacity is a growing issue in the US, pointing out: ‘There often isn’t the multi-year window needed to repower a plant with a different fuel or build a new transmission line. Battery installations can be rapidly deployed in a targeted location and potentially multiply the capacity’s reliability value without creating on-site emissions, noise, or adverse visual impacts.’
The closer battery storage is to the site of consumption, the more valuable it becomes, adds Andrew Marshall, director of product management at Primus Power, a zinc-bromide flow battery developer based in California, US.
Grid-related battery storage has the potential to match supply with demand; manage the flow of energy; extend the life of existing infrastructure; and reduce costs. Battery systems can also help regulate frequency and voltage and act as a buffer for surges of renewable energy. Energy security, particularly for the military, and protecting manufacturing and business operations from power outages (backup) are other potential applications. In remote locations where the grid is non-existent, diesel generators can be cost-effectively replaced with solar/battery systems in ‘island grids’. Batteries also have huge potential where the electric grid is present but unreliable; microgrids based on battery storage could be a reasonable alternative to upgrading the existing grid.
According to market research firm NanoMarkets, the market for chemical batteries for grid storage alone is estimated to reach around $9.4bn by 2020. The emerging technologies consultant Lux Research estimates the current market for battery technologies at $250m, with the total on-grid storage market growing to approximately $15bn in 2017, and the off-grid market (backup power) reaching $2bn by 2020.
NanoMarkets expects mass adoption of grid storage to come in three waves, says principal analyst Lawrence Gasman. Remote applications, island grids and microgrids will be followed by retail applications on the customer side to improve power quality and provide peak shaving, with the last phase dominated by cost-sensitive wholesale and retail peak shifting applications. Peak shaving supplies cheaper stored energy at periods of peak demand; peak shifting moves the electrical power load from peak to off-peak times.
The ideal battery chemistry is safe, dense, and, according to Philippe Bouchard, manager of business development for Eos Energy Storage in New York, US, has a capital cost of $300/kWh or less. ‘Each battery technology has advantages in different applications, and thus the value stream can be maximised by aggregating the benefits across the value propositions of energy storage,’ says Hayes. The choice of battery technologies depends on key performance characteristics, notably cycle life and discharge time, which determine the power to energy ratio.
Lead-acid batteries are the incumbent technology; they are cheap and familiar, and naturally have a place on the grid, according to Kamath. He also notes that they are the most recycled product on the planet. Advanced lead-acid batteries last four to five years and cost $200–300/kWh for a DC system, according to Rittershausen. They currently dominate the backup market.
High-temperature batteries (NaS, NaNiCl) are more costly initially than lead-acid systems – ~$500/kWh for NaS and $1000+ for NaNiCl – but they have twice the lifetime. This technology is well-suited for 3–6 hour utility-scale applications, such as peak shaving and peak shifting of renewable energy. There is around 300MW of NaS capacity and 200MW of NaNiCl capacity installed around the world, according to Gasman.
In contrast, the future of lithium ion (Li-ion) batteries in grid storage applications seems to be uncertain. According to Kamath, Li-ion chemistry may be at or below lead-acid prices for many applications by 2020, while Rittershausen believes the technology is ‘dead in the water’ for most multi-hour peak shifting grid applications due to its cost and potential safety concerns. However, Li-ion batteries do offer superior cycle and calendar life and as costs come down, the technology may present a value proposition where on-site storage is needed, according to Steve Minnihan, a senior analyst with Lux Research. Currently he notes that there is 300MW of Li-ion battery capacity installed worldwide for grid applications.
Energy provider ABB, headquartered in Switzerland, installs Li-ion systems ranging from 25kW to 50–100MW scale, according to manager Pat Hayes. He notes that the small form factor is important in larger systems, because better energy and power density can be achieved. The company has, in partnership with General Motors (GM), found a way to reduce the cost of Li-ion batteries by using repurposed electric vehicle batteries. These batteries have a lot of useful life left – around 70%. Recently, the partnership demonstrated an uninterrupted power supply and grid power balancing system comprised of five used Chevrolet Volt batteries in a module that provides 25kW of power and 50kWh of energy. The module will be tested on the grid later in 2013.
Flow batteries – vanadium redox, zinc bromide and iron chromium – are attractive because they are power and energy dense and can be easily scaled, but the electrolytes used in these systems are prohibitively expensive at around $1000/kWh. Gasman expects these batteries to be an ideal solution for large-scale peak shifting applications as their costs come down.
Many energy companies in the US are investing in battery technology and many have various prototype batteries in the development and pilot phases.
The Aqueous Hybrid Ion (AHI) battery technology from Aquion Energy, Pittsburg, US, has a similar chemical set-up to Li-ion batteries, but uses sodium ions and an aqueous electrolyte rather than a costly organic solvent. The battery has demonstrated thousands of discharge cycles without degrading in the lab and at the product level, according to Ted Wiley, vp of product and commercial strategy. In addition, the AHI technology is stable at 50°C with no need for cooling.
The company has constructed a 1000kWh/year pilot line and will complete a 200MWh/year manufacturing line in the spring of 2014. ‘We are in the validation phase, producing small quantities of our design batteries. They are identical to the ones that will be produced at our commercial facility in high volumes in early 2014,’ explains Wiley. Aquion’s initial target applications include off-grid and island projects, but will move to larger grid services as production volumes increase.
The Znyth chemistry from Eos Energy Storage uses air as one of the active cathode reactant materials, and zinc, which is inexpensive and widely available. The technology employs an aqueous halide-based electrolyte with anticorrosive current collectors and hybrid cathode reactions that provide additional power and efficiency. The company has demonstrated 6000 accelerated charge/discharge cycles in the lab and achieved its power density and energy density targets at a projected system cost of <$300/kWh. ‘We are fairly comfortable that we can offer our technology at $160/kWh or $1000/kW at commercial scale,’ Bouchard asserts.
Eos recently announced product development and demonstration partnerships with seven global utilities and independent power producers. The company aims to deliver MW-scale systems to its partners in late 2014 and is working to ramp up full scale production by 2016. Focusing on peak shifting applications, Eos will test its first pilot demonstration project in New York City with Con Edison in 2014.
Meanwhile, Primus Power, with its zinc bromide flow battery technology, is targeting applications that require power densities similar to those of short duration batteries but with longer discharge durations of 3–4 hours, according to Marshall.
‘We now achieve 250kW of power from a battery that fits into a 20ft shipping container. With up to a four-hour discharge duration at full power, we can deploy 1MW of storage in a fairly small space with a 20-year lifetime,’ he states.
The company has three demonstration projects planned, including its 28MW/84MWh EnergyFarm with the Modesto Irrigation District in central California as an alternative to a fossil fuel plant; a 250kW microgrid deployment at the Marine Corps Air Station Miramar in San Diego, California, that is integrated with a 230kW solar PV array; and a 500kW pilot with Puget Sound Energy with the purpose of integrating of wind power. Primus Power expects commercial production to begin in 2015.
Formed in 2010, in Cambridge, Massachusetts, US, Ambri is commercialising liquid metal battery technology initially developed in 2005 at the Massachusetts Institute of Technology (MIT). Much of the basic science was investigated and key issues addressed at MIT before the company was formed, according to Kristin Brief, Ambri’s director of corporate development. The electrodes – magnesium anode and antimony cathode – and electrolyte (salt) self-assemble due to their different densities. ‘The technology is based on materials that are inexpensive and readily available, is easy to construct, and generates heat internally that keeps the materials in the liquid state (~500°C),’ Brief says.
The use of all-liquid active materials in the battery avoids many issues often experienced with solid active components, thus providing a longer lifetime. The liquid metal battery also has a very fast response (ms) and a power energy ratio of 1:4 to 1:5, according to Brief.
Ambri is building its first 25kWh prototype and expects the technology will be scalable to the MW range. Its first pilot demonstration will be at a military facility on Cape Cod in Massachusetts. Ambri also expects to deploy prototype battery storage units at two to three additional sites in 2014.
Currently, chemical batteries count for a minuscule fraction of the energy used on the grid, and there are numerous hurdles to overcome before they will play a significant role.
‘First, the grid is extremely reliable in the US, so it is relatively easy to provide backup power, and there are many ways to do so,’ says Kamath. ‘Second and equally important is the cost issue. Third, batteries are not fundamental technologies from the utility standpoint. There is an aversion to taking risks and adopting new, unfamiliar and relatively unproven technologies,’ he continues. Utilities are also looking for solutions that last decades, not years. Finally, there are technical issues – with the battery chemistries, and the hardware and software needed to manage the systems and efficiently connect them to the grid, according to Minnihan.
That said, there is a lot of money coming into the sector in the US, largely from the Department of Energy – $50bn in infrastructure investment between now and 2030, according to Bouchard. In addition, both Germany and the US have passed legislation to encourage investment in battery technologies. As demonstrations prove to be successful, confidence will also increase. Methods for determining the return on investment for battery storage projects will then be established, which is important for the market to develop. Increasing renewable use – 41 out of 50 states are looking to increase their renewable energy consumption, according to Bouchard – and the closure of nuclear and coal power plants will further facilitate adoption. ‘Utilities and public utility commissions are starting to take note and look for better solutions,’ Bouchard believes.
The key for battery developers is to partner with companies willing to take on some of the technology and market risk. Commercial-scale production has to be achieved with a low cost structure and the performance fully demonstrated for any chance of success. ‘New battery chemistry developers,’ stresses Rittershausen, ‘have the right idea – create a low-cost, safe, reliable, long-lived battery. There is room in the very large, diverse and growing energy storage market for any tech that hits all of those targets.’
Cynthia Challener is a freelance science writer based in Calais, Vermont, US