At a session during POWERGEN International, representatives from the energy storage industry discussed the risk of fire for energy storage projects that include lithium-ion batteries.

Paul Hayes, CEO of American Fire Technologies walked the audience through what happens when a battery catches fire. He explained that no technology exists to stop Thermal Runaway (TR), the phenomena that takes place when a lithium-ion battery increases in temperature and that changes the conditions in a way that causes a further increase in temperature in battery cells around it. He said he is a big fan of the Battery Management System (BMS) because when working correctly, the BMS should detect an anomaly in a battery cell and shut down the system before TR takes place.

He explained that right before a battery catches fire, it off-gasses, and he showed a video of what that looks like in a cell.

Chris Ruckman, Energy Storage Director at Burns and McDonnell walked the audience through some of the fire suppression systems that exist on the market. Aerosol systems, he said, are not always effective because they usually require smoke and heat to operate and those two elements are not necessarily present when TR of a lithium-ion battery system begins. He added that sprinkler systems are also ineffective since they only cover the top of the battery system and the issue is most likely to be inside a cell.

The only way to counteract thermal runaway is to cool the adjacent cells and neither aerosol systems nor sprinkler systems can do that.

Ruckman said the best preventative measure is to communicate early and often with first responders so they know what type of energy storage system is present at your facility. He recommended that there is signage posted about what battery chemistry is at the site and also lists a person that first responders can call if they have a question.

Almost exactly a year since the Nordic region’s ‘largest’ battery energy storage system to date was announced, Saft has said that the next system to take that crown will be a project the company will work on in Finland.

Saft, the battery energy storage system (BESS) specialist fully-owned by energy major Total, emailed Energy-Storage.news today to reveal details of the project, which is being built to support Viinamäki, a 21MW wind farm in northwestern Finland.

The new project looks set to overtake the 6.2MWh battery system currently being installed at the 44MW Forshuvud hydropower site in Sweden by Finland-headquartered clean energy solutions provider Fortum, which this site reported planned details of in November 2018.

This itself leapfrogged the previous title-holder, the memorably named ‘Batcave battery’ (not to be confused with the similarly named Batwind project, in Scotland) also developed by Fortum, providing frequency regulation to the grid and in operation since 2017. Due to the high shares of renewable energy commonly used by Nordic countries and supportive policies, as well as the success of electric vehicle uptake (particularly in Norway) and the natural cooling impact of the region’s climate that makes it a suitable location for data centres, more are likely to follow.

Saft has been awarded its latest project by Finnish wind developer and operator TuuliWatti. The 21MW battery system has 6.6MWh capacity (thereby just pipping the Fortum project by a fraction). This comprises three Saft Intensium Max 20 HE (High Energy) integrated, containerised energy storage units, each of 2.2MWh. Saft manufactures the systems in Bordeaux, France.

The Intensium Max 20 HE solutions that the project will use were launched to provide ESS applications that generally require fewer than two hours’ storage discharge time. The project for TuuliWatti will perform frequency regulation tasks for the local grid, with the batteries capable of delivering 5.6MW of power for frequency regulation. The systems have an expected lifetime of 15 years.

TuuliWatti portfolio manager Tommy Riski said the Saft high-energy containers will help his company to become “the leading wind developer and producer in the Arctic region, by improving the competitiveness of wind power”.

“They provide a fast response in challenging environmental conditions, as well as the energy storage capacity to support grid stability, allowing us to adjust the output of our wind farm immediately,” Riski said.

The DOE wants information from industry, academia, laboratories and other stakeholders on “accelerating the commercialization of [supercritical carbon dioxide] power cycles that are appropriate for near-term integration with [CSP]” with a focus on “near-term commercial deployment,” according to a notice published in the Nov. 19 Federal Register.

CSP, in which a field of mirrors concentrate the sun’s rays onto a central point like a “power tower” to generate tremendous amounts of heat, can be paired with insulated tanks that absorb the thermal energy. Like a battery, that energy can be deployed at a later time, including at night when there is no PV solar energy.

Many currently-operating CSP projects, such as the nearly-400 MW Ivanpah project that sprawls over 3,500 acres in Southern California, generate electricity by using the thermal energy to produce steam that drives a turbine. But researchers and R&D companies like Brayton Energy are seeking to harness the Brayton power cycle, the basic concept that underlies gas-driven engines like the jet engine, to turn heat into electricity by heating up CO2 to drive a gas turbine.

CSP has been a minor player in the renewable energy industry compared to PV solar for years, with some in the industry viewing it as too cumbersome and expensive to deploy. The CO2 power cycle could be a solution to that problem for CSP, according to the DOE.

The DOE has a goal of cutting the levelized cost of electricity for CSP that can store electricity deployable for up to 6 hours from 18.4 cents per kWh in 2017 to 10 cents per kWh in 2030. For CSP that provides a 12-hour storage duration, the goal is to decrease the cost from 10.3 cents per kWh in 2017 to 3 cents per kWh in 2030. DOE considers “integration with high-efficiency, low-cost power cycles” to be “a key element” for lowering the costs of energy from CSP, the department said in the Federal Register notice.

“Turbines and heat exchangers for [supercritical CO2) are predicted to have significantly lower capital costs than equivalent steam-cycle components due to their compact footprint stemming from the higher energy density of the supercritical fluid,” the DOE notice said. The fact that the process does not use steam could also make CSP more viable in locations where there are limits on water consumption.

In 2018, the DOE awarded $27.7 million in funding for projects related to long-term energy storage, including $2.7 million for the National Renewable Energy Laboratory to work on low-cost thermal energy storage systems that utilize closed-loop Brayton cycle turbines and $1.99 million to Brayton Energy. With the aid of competitive grants from the DOE issued since 2010, the New Hampshire-based Brayton Energy has been developing the solar receiver and energy storage subsystem for a prospective CSP plant that would use the Brayton power cycle.

Swedish thermal energy storage solutions provider Azelio has teamed up with US-based Biodico to develop 120MW in thermal energy storage projects in Atascadero, California, US, by 2024.

Biodico is planning to create biofuel production centres, which will be powered by the clean energy generated by the on-site renewable resources to reduce greenhouse gas emissions.

For these production centres, Azelio will be supplying nearly 9,000 units, which will supply Biodico’s biofuel production system with electricity on demand.

Azelio CEO Jonas Eklind said: “We are moving at a good pace, and I am pleased to see the substantial interest in Azelio’s technology manifested by a third MoU in a short period of time. At Azelio, we are particularly excited about gaining ground in the North American market.

“The project in California will demonstrate our solution’s capabilities in storing and dispatching energy from both solar PV and wind power, allowing both Azelio and Biodico to build a valuable experience needed to deploy our solution on a larger scale.”

The series of projects that will be developed under the new initiative includes a 13kWe energy storage that is slated for completion in 2021, followed by other projects including 15MWe in 2022, 35MWe in 2023 and 70MWe in 2024.

Azelio’s systems will feature solar PV, wind, as well as its power storage unit, which will ensure supply of base-load energy to the process around the clock.

Biodico president Russell Teall said: “Biodico sees Azelio’s system as the main part of its energy supply for its modular renewable biofuel production.

“The ability to provide renewable energy 24/7 is crucial at both a technical and commercial level. ­­Environmentally it is the right thing to do, and it has financial benefits at the same time.”

As US states work to address and enable the swift growth of distributed energy resources (DERs), including solar and energy storage, the issues surrounding their interconnection to the electric grid require close attention.

Not only to maintain safety and reliability as new technologies connect to the grid, but also to provide a clear, transparent and efficient process for customers, developers and utilities
alike.

Interconnection procedures are the rules of the road for the grid. Without common rules and predictable processes, gridlock and costly projects can result. Alternatively, the adoption of statewide interconnection standards (i.e., rules that apply to all regulated utilities) that reflect well-vetted best practices can provide greater consistency across utilities and help streamline the grid connection process for all involved stakeholders. Interconnection rules are designed to handle current and anticipated growth of DERs, while also enabling more cost-effective and efficient clean energy projects.

In particular, interconnection standards can help states address the integration of newer technologies that are transforming the energy system, i.e., energy storage, solar-plus-storage, and smart inverters. Energy storage in particular requires more explicit provisions to address its unique flexibility and ability to operate differently based on different applications.

What’s so special about energy storage?
So, for example, energy storage is controllable in a way not typically seen with distributed generation, such as rooftop solar. Many energy storage systems can be designed with the capability to limit or prevent export onto the grid, which impacts how the system should be studied and interconnected to the grid.

In IREC’s recently released 2019 Model Interconnection Procedures, we take the first steps toward defining a clear interconnection process for energy storage systems to provide a useful starting point for states navigating these issues. By addressing the unique qualities of energy storage, the 2019 procedures create an initial framework for reviewing energy storage and verifying energy storage system capabilities.

IREC’s model procedures have been around since 2005 (with updates made in 2009 and 2013) and have served as a template for nearly all states that have adopted statewide interconnection standards. In addition to addressing energy storage, the 2019 edition provides other needed updates to reflect new best practices for interconnection.

However, the model procedures do not yet resolve every question around energy storage.

For example, they do not address how to screen those energy storage systems that may have some “inadvertent export” for a very short duration in response to sudden customer load fluctuations. But as the interconnection of energy storage evolves in the coming years, best practices for how best to analyse their grid impacts will continue to emerge.

The Austin SHINES program set out to establish a working business model for distributed energy resource (DER) optimization in grid, commercial and residential applications. Backed by a $4.3 million grant from the U.S. Department of Energy’s Solar Energy Technologies Office (SETO), the program aims to establish repeatable methodologies for designing and operating energy storage and solar PV on a grid.

Over the last three years, Austin Energy has designed and installed DERs with a diverse team of partners. Doosan GridTech collaborated with the utility to develop software control architecture and optimization strategies that enable load to be served at the lowest possible cost in a system with high distributed solar penetration. SHINES resources consist of Doosan’s distributed energy resource optimizer platform, two utility-scale energy storage systems (ESS) designed and installed by Doosan, several customer-sited ESS at residential and commercial properties, smart inverters, real-time data feeds, and a vehicle-to-grid (electric vehicle) component.

The program includes more than 5 MW total of energy storage and PV assets – with resources on both sides of the meter. The scale and variety of Austin SHINES resources allow the utility to explore, test and evaluate different asset mixes and dispatch strategies under different scenarios to develop and document replicable best practices. SHINES resources include:

Utility-scale energy storage + PV

• 2.5 MW PV at La Loma Community Solar Farm
• 1.5 MW / 3 MWh Li-Ion Battery Storage at the Kingsbery location
• 1.5 MW / 2.5 MWh Li-Ion Battery Storage at the Mueller location
• Commercial energy storage + PV

• Aggregated storage installations at three site
• One 18 kW / 36 kWh Li-Ion Battery Storage installation
• Two 72 kW / 144 kWh Li-Ion Battery Storage installations
• All sites have existing solar (300+ kW)
• Residential energy storage + PV

• Aggregated storage installations at six homes (10 kWh each)
• Each with existing rooftop solar
• Utility-Controlled Solar via Smart Inverters at twelve homes
• Autonomously Controlled Smart Inverters at six homes

With just over 3 GW deployed worldwide, grid battery storage remains a small business today, but recent developments demonstrate that the sector is thriving. In the United States in 2018, more than 300-MW battery storage was deployed, led by California. Globally, network operators are testing projects in Italy, the United Kingdom, Spain, and other regions. In Australia, China, United Arab Emirates (UAE), and the United States, large energy storage projects are ready to deliver more than 100 MW of capacity for up to six hours.

While the benefits of deploying battery technologies for grid management are clear, there has been limited development of the global grid-battery market because of three main reasons:

1. Costs

Costs of batteries are still too high for most grid applications to be viable, other than where local regulations incentivize deployment. However, cost of battery storage continues to drop year after year, largely because of battery manufacturing for electric vehicles (EVs). We expect the cost to fall within the US$100/kWh range by the mid-2020s. This cost decrease, combined with a stacking of revenue streams and battery applications, will lead to a significant proliferation of positive business cases.

1. Regulations

In most regions, regulatory barriers prevent network operators from owning and operating battery storage, except in Italy, where the regulatory framework has been amended. System operators are therefore restrained from developing battery-storage solutions beyond pilot projects. It is imperative that clear regulatory frameworks and market mechanisms are established to allow the development of storage assets with clear targets for deployment. For example, the California Public Utilities Commission (CPUC) requires utilities to build energy-storage capacity and has clarified the market rules for battery aggregation. Following these moves, California’s largest utilities have procured or are seeking approval to procure almost 1500 MW, as of summer 2018.

There is also a strong argument for providing direct incentives for use of battery storage to catalyze development and lower costs which has worked in the renewables sector. Consider the contrast between Germany and Spain, two European countries with relatively high renewables penetrations. In Germany, where incentives are provided, the residential storage market is booming and reducing stress on the grid. In Spain, battery deployment remains very limited.

1. Alternatives

Batteries are far from being the only option for balancing supply in a distributed energy grid with high renewable use. Other approaches include:

Good regional and international interconnectivity decreases the intermittency of renewables over large areas and allows for a greater mix of power sources to be used.

Fast-start and rapid ramp-up fossil-fuel plants have also played a key role in meeting peak power supply requirements and will remain important in the future.

Demand side response (DSR) has already been widely tested as a way to balance the grid by incentivizing end-consumers to reduce their consumption or switch to behind-the-meter generators in response to grid requirements.

Part IV of Solar Builder’s excellent Countdown to 2020 series about California’s new home solar mandate included this statement: “Speakers at the California Solar Power Expo… expect homebuilders to skip solar-only systems to comply with the Title 24 mandate and go straight to solar + storage systems.” Is that expectation realistic or are those industry experts looking through rose-colored glasses?

The answer is an unwavering “maybe.” Remember how long it took consumers to believe that solar energy systems actually pay for themselves. Now we’re trying to convince builders that consumers are ready to believe that solar + storage is an even better value proposition than solar alone? That shift won’t happen overnight. People are innately skeptical when an offer sounds too good to be true. It also will require considerable education considering that most builders and consumers know very little about solar energy storage today.

Whether or not builders and their customers buy into solar + storage depends mainly on how well the solar industry conveys the benefits of energy storage systems. And, while it sounds callous to say, the truth is that the wildfires and power outages ravaging California are going to goose the adoption rate for solar storage.

The value equation for storage
Absent power outages, the primary selling point for solar energy storage in markets (such as California) where you have tiered electricity rate structures is its ability to offset utility rates during peak demand times, when power from the grid is priced at a premium. That is still a compelling benefit.

However, the greater value of battery storage in California today is its ability to provide some electricity during a power outage. With Pacific Gas & Electric on the proverbial hot seat for having caused the 2018 Camp Fire—the deadliest wildfire in the state’s history—the company has taken the proactive step of cutting power during high-risk, red-flag warning times to minimize the risk of contributing to wildfires (and no doubt to avoid future liability).

As of this writing, Pacific Gas & Electric has cut power numerous times in recent weeks. Southern California Edison and San Diego Gas & Electric have also recently implemented forced outages for their customers.
Since hot, dry and windy weather is a given in California, it’s safe to assume these rolling blackouts will be implemented again and again, and that solar energy storage systems will become more valuable and popular as a result. The media picked up on this trend during PG&E’s planned outage in mid-October. The San Jose Mercury News reported how homeowners and businesses ranging from the Fremont fire station to Apple turned to energy storage to keep critical functions operating.

At its seventh annual conference and expo, Energy Storage North America (ESNA) last week announced the winners of its innovation and champion awards, inducting them into the organization’s hall of fame.

Based on public, online voting, the ESNA sought innovators in the fields of front-of-meter storage, behind-the-meter storage, and microgrids. Additionally, they recognized utility and policy champions that have made significant efforts to enhance energy storage. Respectively, these efforts honored work on the energy storage ecosystem, services supplied to customers and the grid, unique technology solutions, financing, or partnerships.

“The individuals and organizations we’re recognizing with this year’s ESNA Awards have made significant contributions to the growth and maturation of energy storage as a mainstream grid resource,” Janice Lin, ESNA Conference Chair, said. “Their dynamic leadership and skillful execution serve as greatly needed role models for the global clean energy transformation.”

For front-of-meter efforts, the Goderich Advanced Compressed Air Energy Storage Facility as powered by Hydrostor was named the winner. On the other side of the meter, Connected Solutions — as powered by National Grid — took home the award. Nantucket Battery Energy Storage System, as powered by National Grid, received top honors for its microgrid technology.

The champions of the day were Martin Adams, general manager and chief engineer of the Los Angeles Department of Water & Power, along with Alicia Barton, president and CEO of the New York State Energy Research and Development Authority. Adams was the utility champion, while Barton was the policy champion.

The researchers propose that a motorized system similar to a ski lift could pull containers full of sand to a crane at the top of a mountain. The sand can then be sent back down the mountain propelled only by the force of gravity, generating electricity in the process.

The basic concept is similar to a gravity storage technology proposed by the Swiss company Energy Vault, which recently received a greater than $100 million equity investment from SoftBank’s Vision Fund. That technology generates electricity through gravity by lowering concrete blocks in a tower.

Lithium-ion battery storage is the fastest-growing storage type and utilities across the U.S. have procured battery storage as a way to back up intermittent renewable energy. But the length of time that they can deploy energy — typically four hours or shorter for — may not be long enough for the greater and greater amounts of solar and wind resources needed to come online to meet emissions reductions goals.

“High-renewables grids, as mandated by many states, will require extremely long durations of storage, potentially on the order of 10-20 hours to shift variable solar power to cover nights and cloudy days, and weeks or even months to shift energy from high-wind months to lower-wind periods,” Wood Mackenzie head of energy storage Daniel Finn-Foley told Utility Dive. He noted that lithium-ion batteries “scale up poorly,” with costs effectively doubling every time the duration of a lithium-ion battery system doubles.

The authors of the IIASA study claim that mountain gravity energy storage (MGES) can open up possibilities for long-term storage in new locations. Pumped hydropower storage, one of the most common forms of energy storage currently in service, is an example of long-term storage and can deploy stored energy for around 6 to 20 hours.