Used electric vehicle (EV) batteries can be repurposed to store electricity generated by large scale solar plants, according to an MIT study.

The U.S.-based researchers claimed even devices which have lost 80% of their original capacity could offer a better investment prospect for solar-plus-storage projects in California than purpose-built, utility scale batteries, not least because such ‘second life’ EV batteries could cost as little as 60% of their purchase price.

MIT research co-author Ian Mathews conceded technical hurdles remained to the deployment of used EV batteries on a large scale, such as aggregating batteries from different manufacturers and screening which devices could be reused. However, Mathews insisted used EV batteries still offered a persuasive enough business case to justify the cost of recovering them, screening performance and redeploying them.

Optimal operation

The researchers used a semi-empirical model – including some ‘pre-cooked’ calculations – to estimate battery degradation, and concluded operating such aggregated storage devices at 15-65% of full charge would extend their second life. “This finding challenges some earlier assumptions that running the batteries at maximum capacity initially would provide the most value,” the scientists stated.

Mathews said the feasibility of second-life EV battery storage would depend on the regulatory and rate-setting regimes under which they would operate. “For example, some local rules allow the cost of storage systems to be included in the overall cost of a new renewable energy supply, for rate-setting purposes, and others do not,” he said.

Algorithms

The academic added, longer-term pilot studies are needed to assess the potential of such systems.

The MIT researcher noted control algorithms may be adapted during projects to lengthen the feasible lifetime of such facilities. “We think this could be a great application for machine-learning methods,” said Mathews, “trying to figure out the kind of intelligent methods and predictive analytics that adjust those control policies over the life of the project.”

The successful reuse of electric vehicle batteries for grid scale storage would also require buy-in from EV manufacturers, energy storage businesses, solar project developers and power electronics specialists, added Mathews.

Sweden-based storage system provider Northvolt has developed a new lithium-ion battery based on a modular approach that makes it suitable for a range of different energy market segments.

The manufacturer said the new Voltpack Mobile System is an ideal solution for remote or weak grids and EV charging. However, it has claimed that it can also be used for balancing, grid flexibility, and ancillary services.

“Voltpack Mobile System delivers up to 250 kW with a scalable capacity from 245 to 1225 kWh of available energy,” Northvolt said. “The system scales through a central interface hub, which can connect in parallel up to five self-contained Voltpacks, each containing three liquid-cooled, industrial-grade battery Voltpack Cores.”

Voltpack Mobile Systems can be connected in series if more storage capacity is needed, with the central hub serving as an interface for applications such as home inverters and auxiliary systems. The battery technology, as well as the inverter systems and battery management system, were designed and manufactured by Northvolt.

Vattenfall

Utility Vattenfall is testing the system at its facility in Alvkarleby, Sweden. “Vattenfall will be the first to offer the battery unit to the market, and have identified the need for sustainable solutions at industries, for microgrids, construction sites as well as for event organizers,” Northvolt said.

Torbjorn Johansson, head of Vattenfall Network Solutions Sweden, said that the company will offer the battery storage solution as part of its “power-as-a-service” concept. “(This) means that we deliver a complete package with ownership of the energy storage and manage it to the specification of the customer,” he added.

Drammen Eiendom KF – a company owned by the municipality of Drammen, Norway – has developed a project to store solar energy as heat. The system can store energy provided by 150 m2 of solar thermal collectors and 1,000 m2 of PV panels in 100 boreholes in granitic gneiss rock, each with a depth of approximately 50 meters.

“GeoTermos is expected to return around 350,000 kWh/year in the form of heat at various temperature levels during the heating season,” said Randi Kalskin Ramstad, a shallow geothermal energy and hydrogeology specialist at the Norwegian University of Science and Technology (NTNU) and engineering services provider Asplan Viak.

The electricity provided by the PV installation produces heat by using air as a heat source for the CO2 heat pump. The heat is then stored in the boreholes during the spring, summer and fall. In the winter, it is used for low-temperature heating in a number of nearby school buildings.

“The system performance of the energy system is quite high,” Kalskin Ramstad told pv magazine. “The operation of the plant has now just started, with heat charging of the boreholes.”

Water is used as a collector fluid in the boreholes, which provides several advantages compared to glycol-based collector liquid, including lower viscosity, better thermal properties, and lower costs. It is also environmentally friendly.

The GeoTermos system – with energy storage, a heat pump, and an accumulation tank – is able to provide approximately 300 kW of heat power for short periods during peak load, and is regulated by the temperature levels and heat power demands.

PV system

The 200 kW PV installation, which was built by local installer Solar Technology Scandinavia SAS, was deployed across four different rooftops at a school. The NOK 3 million ($299,000) system relies on 616 Panasonic VBHN 325 SJ47 PV modules and SolarEdge three-phase SE25K inverters.

The UK government has confirmed changes to the Capacity Market which are designed to remove barriers for demand side response (DSR) and energy storage, making it easier for clean technologies to compete in auctions.

The changes include reducing the Minimum Capacity Threshold from 2MW to 1MW. DSR will now be able to apply to prequalify to bid for all the agreement lengths in the capacity market, provided they can demonstrate the relevant CAPEX threshold.

It will now provide legislative underpinning for the long-standing 50% set-aside commitment for T1 auctions, along with methodology for working out the minimum amount of set-aside. T1 auctions are set up to guarantee capacity is available to the system to keep Britain’s lights on the following winter, whereas the other type, T4 auctions, look to secure adequate capacity four years ahead.

A formal, annual review of new capacity technologies that are not currently competing in the Capacity Market but which could help to provide security will be brought in.

Reporting and verification for the introduction of CO2 emission limits will also be brought in, with emissions limits set to apply to capacity which existed before 4 July 2019 from 1 October 2024. Britain’s European neighbour France recently introduced its first ever Capacity Market auction with a low emissions requirement, awarding contracts to more than 250MW of energy storage assets as a consequence.

Changes help clear the path forwards for clean technologies, association chief says
“A common barrier to advancing the UK’s energy storage sector is that our electricity grids and major energy policies from government are set up for an age of large-scale, centralised fossil power stations,” explained Dr Nina Skorupska CBE, chief executive of the UK’s national Renewable Energy Association (REA).

By any measure, 2019 was a breakout year for energy storage in the U.S. Fueled by improved economics, increased demand for resilience, and the ever-increasing integration of intermittent renewable generation, energy storage installations hit an all-time high of 522 megawatts/1,113 megawatt-hours last year.

Though coronavirus-related supply chain disruptions, macroeconomic damage and uncertainty have lowered 2020 installation forecasts, analysts remain bullish on the longer-term prospects of storage. According to Wood Mackenzie Power & Renewables, global installations will reach 15 gigawatts per year by 2024.

The explosive growth of storage is reminiscent of solar and wind, both of which have become mainstream generation sources thanks to dramatically improved economics, expanded manufacturing scale, policy support, and customer demand. However, like solar and wind, battery storage’s future growth depends on innovations that go beyond improved technologies and manufacturing-related economies of scale.

For example, project financing and business models are in dire need of innovation in order to both lower the costs of storage and make it more readily available to the commercial and industrial (C&I) space, developers and other customers that could directly benefit from its implementation. Addressing these often-overlooked areas will be a critical component of unlocking the transformational potential of storage.

Deconstruction leads to innovation

A close examination of North American battery storage costs led to the launch of Prisma Energy Solutions in 2017. “We noticed that the all-in cost of projects didn’t compute with what we understood,” said Matt Whitaker, Prisma’s Head of Technology and Procurement, who has decades of experience in energy, finance and technology. “So we started to deconstruct what those were.”

Electrochemical batteries have been around for more than 100 years and solar photovoltaic (PV) panels have been in use for half a century. During the early days of solar, users deployed PV panels to charge batteries in places far from a power line or gas station. Those batteries powered things like satellites, weather stations and remote homes. Around the turn of the century, people began connecting PV systems directly to the electrical grid.

At first, the grid connection was for purely scientific or ideological reasons, and, as regions and businesses offered incentives and PV sped down the cost curve, people used PV to save money on electricity. In 2004, PV systems installed without batteries outnumbered battery-based systems for the first time – by 2010, solar-plus-storage systems were relegated to a small niche of the booming solar industry. But now the industry is coming full circle.

In October of 2015, Hawaii’s public utilities commission became the first in the U.S. to start limiting grid-direct PV installations due to impacts on local grids from midday power exports. New systems would not be allowed to send surplus power back to the grid indiscriminately. Thanks to a small but thriving number of businesses that still installed off-grid and backup systems, many Hawaiian solar customers deployed batteries to ensure their PV output was stored for nighttime use rather than pushed back to the grid. The writing was on the wall: PV and batteries were not as separable as we thought.

Since then, utility rates in several more states have been made more sophisticated, in part to discourage the export of solar PV power onto the grid at inopportune times. The industry is responding by making batteries available to most new solar customers. While the added cost of the batteries can make the financial payback of these PV systems less lucrative than the direct grid models, batteries provide additional resilience and control for the system owner – which is increasingly important to consumers and businesses alike. All of the industry signs are clear: storage is going to be part of most solar PV systems going forward.

Sungrow is to partner with Huanghe Hydropower, providing PV inverter and energy storage systems for a major solar-plus-storage project in Qinghai Province, China.

Chinese developer Huanghe Hydropower Development is bringing forward the 202.86MW/202.86MWh solar-plus-storage project, selecting Sungrow’s 1500V SG250HX inverters alongside the manufacturer’s integrated energy storage systems.

Sungrow said the combination of the two technologies enabled shorter construction times and easier operations and maintenance, while also bringing additional benefits to the grid when operational. The system will come with an embedded sub-array energy management function that can, in turn, be used to control the output of the solar farm by utilising its co-located storage capacity, allowing for improved accuracy of solar generation forecasts.

Huanghe Hydropower is developing the project within a hub of ground-mounted solar plants in a particularly remote region of China, selected for its high irradiation. These “bases” are then connected to transmission grids in the country using ultra-high voltage (UHV) technologies, facilitating the transfer of power from the west of China to the country’s densely populated east.

Describing the project as a landmark for the country, a spokesperson for Huanghe Hydropower said Sungrow’s energy management system was the first to pass functionality tests in controlling both solar PV and energy storage system output.

Jack Gu, senior vice president at Sungrow, said the combination of solar with storage and other technologies was critical to reducing the levelised cost of electricity (LCOE) further.

Zinc battery storage manufacturer Eos Energy Storage was awarded contracts for systems providing on-site power resiliency at an oil refinery in Greece.

New Jersey-based Eos has partnered with Motor Oil Hellas and Ingeteam on the two projects. Eos will design, build and deliver a 1-MW/4 MWh behind-the-meter battery system at Motor Oil’s Corinth Refinery in Athens.

“This project is not only our initial entry into the dynamic Greece energy storage market, but it’s also an opportunity to demonstrate the many advantages of our storage technologies including performance, safety, and environmental conditions,” said Joe Mastrangelo, CEO of Eos Energy Storage.

The project with Ingeteam calls for Eos to provide the full AC-integrated system for the INGECON Bseries inverter and miniskid MC solution and EMS plant controller.

The work at the Corinth Refinery is focused on helping lower costs, shaving peak demand and optimizing the site’s grid resiliency. The high temperatures of the Mediterranean climate post challenges for lithium ion chemistries which require HVAC additions, and the Eos’ zinc system does not, according to the release.

Eos will plan, design and commission its patented Znyth storage system. This technology employs a unique zinc-halide oxidation/reduction cycle packaged in a modular, sealed, static-cell, flooded, bipolar battery.

“We consider Eos battery technology as the most competitive and attractive one compared to Li Ion batteries, capable of offering a lot of opportunities in large scale BESS in the future,” said Vassilis Viziryiannakis, Head of Electricity Business of Motor Oil Hellas.

Merchant energy storage has become an investable asset class in the UK, a provider of battery optimisation services has said, with the market moving away from an emphasis on contracted revenue streams for supplying grid services.

Dr Ben Irons, co-founder at Habitat Energy, said that “three years or so ago, firm frequency response (FFR) contracts were where 100% of the action was for battery storage in the UK,” as battery storage became eligible to provide the grid-balancing service to transmission system operator (TSO) National Grid.

However, according to Irons, the idea of a contracted revenue stream “gave a false sense of security,” with contracts generally only two years long for FFR, and even the longer contracts award through the UK’s landmark 200MW tender for enhanced frequency response (EFR) were four years and were “quickly snapped up”.

Speaking to Energy-Storage.news following his appearance at last week’s online Energy Storage Digital Series conference – at which he explained instead that merchant opportunities including arbitrage have matured to provide decent revenues for Habitat’s clients – Ben Irons said that those two or even four years contracts were not “nearly enough to cover the investment horizon or reach a payback on capex, without coming back for a series of further contracts later”.

“The problem was there was no guarantee on the price for those subsequent contracts, as many early battery investors learned to their cost when the FFR price dropped from 19 to 5 £/MW/hr in the space of a couple of months,” Ben Irons said.