The third longest railway system in the world could be on the verge of an energy storage makeover. That would be Russian Railways, which sprawls over 85.5 thousand kilometers. A little over half that length is electrified, and if all goes well with a new R&D project, the little could turn into a lot.

That’s not necessarily a gigantic win for climate action, considering that Russia hasn’t exactly been leading the vanguard on renewable energy. However, more and better railway electrification at least opens the door for more renewables, so let’s take a closer look and see what’s going on.

The new energy storage project is a joint venture between Russian Railways (RZhD) and the aggressively renewable energy company Enel Group.

As described by Enel, the partnership will focus on a first-of-its-kind use for energy storage in railway systems. The aim is to develop a relatively low cost strategy for improving system operations without getting into more expensive grid upgrades.

So, what does this mean? Something exotic, like flow batteries? Power-to-gas (aka hydrogen)? How about the concentrating solar + hydrogen combo?

What Kind Of Energy Storage?

So many questions! For an answer CleanTechnica reached out to Enel, which provided this backgrounder (breaks added for readability):

The partnership will start off with a testing phase, which will run for up to three months and is expected to begin by the end of the year, involving the installation of a single battery in RZhD’s laboratory where the technology can perform in a controlled environment.

The lithium batteries, with a minimum capacity of 10 MWh, can be activated automatically through Enel X’s software during times of peak demand with the aim to help respond to the growing energy demand of railway systems whose faster, more powerful and larger trains could be slowed in some instances to avoid putting strain on power grids.

The duck curve is named for its resemblance to a duck, with its peaks and valleys highlighting the effect solar production has on the power demanded from thermal generators and hydropower resources throughout the day. Advancements in energy storage technology are providing a new method for narrowing the timing imbalance.

Since 2006, solar energy production has grown at an annual rate of 59%, according to the Solar Energy Industry Association. Solar energy’s share of total U.S. energy generation skyrocketed from just 0.1% in 2010 to almost 2% in 2017. In the past three years, it has comprised an average of about one-third of all new energy capacity additions.

This rapid growth has resulted in a fundamental challenge for system operators by creating an imbalance in the supply and demand of energy on the grid known as the “duck curve.” The duck curve (Figure 1), which derives its name based on a chart published by the California Independent System Operator (CAISO) in 2013 resembling a duck, highlights the sharp midday drop in energy demand resulting from peak solar energy production followed by a short, steep ramp-up in the early evening hours as demand for energy increases and solar energy production falls.

In its report, CAISO noted three major problematic conditions affecting grid management that are exemplified by the duck curve. They are:

■ The creation of short, steep ramps caused by system operators being forced to quickly bring on or shut down energy generation to meet demand over a short period of time. To address this condition, CAISO stated that a flexible energy resource is necessary to quickly react to adjust energy production to meet sharp changes in demand.

■ The fact that peak midday solar production exceeding demand results in the risk of oversupply, which must be managed to avoid the costly consequences associated with overgeneration, including increased costs from curtailing energy production and reduced environmental benefits as a result of such curtailment.

■ The management of such oversupply during the midday hours results in decreased frequency response capabilities, which are caused by fewer energy resources being available to automatically adjust energy generation to maintain grid reliability. That is, as renewable generation resources (which typically do not have automated frequency response capability) deliver energy, conventional generation resources (which can typically provide automated frequency responses) are displaced. As a result, the grid becomes less reliable and is increasingly subject to disruptions. To avoid this risk, the grid needs access to automated frequency response systems that can quickly and automatically ramp up or down in the event of sudden interruptions.

Modelling can play a crucial role in identifying the optimum level of energy storage for a project. A key factor when planning energy storage systems (ESS), for example for a microgrid, is to determine the expected cost savings and performance benefits provided by various ESS configurations.

Battery modelling offers a powerful way of predicting the lifetime performance and return on investment that will be provided by each ESS option.

Fuel savings are often a key factor in the choice of energy storage configuration, especially for microgrids which are often located in remote communities and rely on diesel generation, with logistical challenges around fuel delivery. However, cutting fuel consumption is just one of the purposes of battery modelling for microgrids.

Battery modelling techniques continue to evolve to better address the wider context of microgrid and renewable energy deployments. For example, simulations are now key to the project development process, as they deliver insights into renewable and storage applications ahead of deployment and help determine how much power and energy are required overall.

Precise modelling

Modelling an entire microgrid at a high level is a valuable exercise in assessing the viability of different deployments of renewable energy schemes with storage. However, when it comes to modelling the detail of these systems – such as bridging between multiple diesel generators in a large microgrid, or optimizing the set-points for operating with diesel generators in a smaller microgrid – more precise modelling is required.

High-frequency data, with granularity of no more than ten-minute intervals, is valuable. Such modelling provides insights into system operation, including diesel synchronization and cool-down times, to minimize diesel starts, maximize fuel savings and optimize battery life.

High-level modelling is typically based on hourly data, and the granularity of ESS dispatch is correspondingly coarse. This kind of modelling is feasible even with minimal data input.

Public power utility Salt River Project (SRP) will launch Arizona’s first battery energy storage project to provide flexible peaking capacity.

Energy storage firm Fluence will supply a 10-MW, four-hour duration system to AES Corp., which has a 20-year agreement with SRP for the project to be built in Chandler. AES owns Fluence in partnership with Siemens.

Fluence said in a press release that its Advancion energy storage technology platform was selected “to meet SRP’s need for an industrial-strength solution with high dependability, reliability and the ability to evolve over long-term operations.” It will also help SRP asses how to best scale-up future energy storage projects across its 2,900-square-mile electric service area.

Arizona has proposed procuring 3 GW of energy storage by 2030—the largest in the nation. Last week, New Jersey enacted a law directing the Board of Public Utilities to begin work paving the way for a goal of 600 MW of energy storage by 2021 and 2 GW of energy storage by 2030.

The states join several others who have standalone energy storage targets, including California, Oregon, Massachusetts, and New York. (For more, see POWER’s March 2018 infographic, The Big Picture, “Energy Storage Mandates”).

In a report released this May, consulting firm Deloitte noted that uptake of battery storage in electric power grids worldwide continues broadly, spurred by a range of market drivers. “Battery storage is flexible, can be deployed quickly, has multiple applications, and can produce numerous value streams—not to mention that battery prices are falling faster than anticipated,” it noted.   Battery storage growth is also being fueled by advances in adjacent digital technologies—such as artificial intelligence, blockchain, and predictive analytics. These drivers “are giving rise to aggregated solutions and innovative business models that were nearly inconceivable a few years ago. Start-ups around the world are rapidly commercializing intelligent networks of “behind-the- meter” batteries to benefit electricity customers, utilities, and grid operators,” it added.

Indian EPC firm Sterling and Wilson has won its first large-scale hybrid and energy storage turnkey EPC contract order in Western Africa, including what it believes to be both the largest battery storage project and single battery installation in the whole continent.

The scope of work – the company’s formal entry into the hybrid and energy storage space – includes design, EPC and O&M of a captive hybrid microgrid powered by solar, diesel and battery storage.

In a release, Sterling and Wilson said this would be a “first of its kind” project powering behind-the-meter clients in the educational sector in Western Africa with 30MWh of battery energy storage spread across three sites, including a single battery installation of 17MWh.

The microgrid backed with batteries will be able to provide one-day power autonomy to the educational institutions, helping them to run efficiently and to spend more on school programs.

Deepak Thakur, CEO, hybrid and energy storage, Sterling and Wilson, said: “Lack of power supply is a primary barrier in imparting effective learning and development of any nation. We are extremely glad to have bagged our landmark first project in the hybrid and energy storage space, which not only consists of the largest battery installation in Africa to date but also hopefully proves to be a marquee installation empowering future generations. We are confident of meeting the most stringent quality, safety and financial needs of our client given our combined global expertise of having delivered over 7GW of solar, diesel and gas-based power plants on a turnkey basis to date.”

Having recently announced its major foray in hybrid energy storage solutions, Sterling and Wilson’s newly-formed business unit is actively pursuing further such opportunities across Europe, the Middle-East, Africa, Asia and Australia as well as the US.

The company declined to comment on which specific country the African project will be located. However, in an exclusive interview with Energy-Storage.News, Vish Iyer, global head of business development, strategy and marketing for the hybrid and energy storage division at Sterling and Wilson, will be providing many more details on the win later this week.

New Jersey has adopted an energy storage goal, becoming the fifth state with some form of energy storage target.

The state’s storage goal is part of a broader legislative effort, A 3723, that was signed into law last week, along with a law establishing a zero emission credit program for nuclear power plants.

The Renewable Energy law requires New Jersey’s Board of Public Utilities to submit a report on energy storage to the governor and legislature within one year. Six months later, the BPU is required to begin work to establish a process and mechanism “for achieving the goal of 600 megawatts of energy storage by 2021 and 2,000 megawatts of energy storage by 2030,” according to a New Jersey Assembly Appropriations Committee statement.

The statement says the report should include ways to increase opportunities for energy storage in the state, including recommendations for financial incentives by public and private entities.

The state’s storage goal is “the most aggressive one I’ve seen,” Navigant Research senior research analyst Alex Eller told Utility Dive.

California set an energy storage target of 1,300 MW by 2020 with the passage of AB 2514 in 2013. Since then, AB 2861 added another 500 MW to the state’s goal. Oregon followed suit in 2015, setting a target of 5 MWhby 2020. Massachusetts passed an energy storage initiative in 2016 and has set its target at 200 MWh. And, until New Jersey’s law, New York was on track to have the most aggressive energy storage target — 1,500 MW by 2030. A regulator on Arizona’s Corporation Commission has proposed a 3,000 MW by 2030, but it has not yet been approved.

The states’ efforts are not directly comparable, however. The time frames vary and some targets, like California’s are mandatory, while other’s like Massachusetts’, are not. And the level of New York’s target is not yet codified but has only been indicated by statements from Democratic Gov. Andrew Cuomo. The various targets do, however, give an indication of how states are stacking up with regard to energy storage policies.

New Jersey’s goal could create momentum for other similar processes across the country. Arizona and Nevada have both passed laws calling for their regulators to investigate energy storage targets. And several other states — including Colorado, Illinois, Indiana, Minnesota, Missouri, New Mexico, Ohio and Vermont — have begun proceedings on energy storage policies.

Electric vehicles could become a vital asset for California grid operators who are struggling to bring more renewables online. The state’s rapid adoption of solar power is contributing to a problem known as the “duck curve” — a deep dip in demand during solar-saturated midday hours, followed by a steep ramp in the evening as solar power fades away.

Regulators have responded by mandating that the state’s three biggest utilities procure a total of 1.3 gigawatts of energy storage by 2020. But researchers say they’ve found a more effective way to mitigate the duck curve using strategic EV charging.

Scheduling electric vehicles to charge in the middle of the day rather than the evening would help balance the grid by storing surpluses of electricity that would otherwise need to be curtailed. The effect on the duck curve would be equivalent to adding 1 gigawatt of storage capacity at a cost of $1.45 billion to $1.75 billion, according to a new analysis from the Department of Energy’s Lawrence Berkeley National Laboratory.

“Our results show that…California can achieve much of the same benefit of its Storage Mandate for mitigating renewable intermittency, but at a small fraction of the cost,” wrote the paper’s authors.

If some vehicles feed electricity back to the grid during peak evening hours, the benefits become even more pronounced. A mix of vehicles doing one-way and two-way charging would shave almost 5 gigawatts off daytime over-generation and evening peak demand, while keeping up-ramps and down-ramps within current levels. If just 30 percent of workplace chargers and 60 percent of home chargers allowed EVs to provide power to the grid, it could offset up to $15.4 billion in stationary storage investment, according to the study.

Researchers say the cost to implement such a plan would be relatively small, because most of the technology is already in place. Grid operators would theoretically be able to control charging in real time using software inside the vehicle, charging station, or both.

“A lot of vehicles are already internet-connected devices…so if it’s possible to use the existing communications channel to get this additional value for the grid, that’s fantastic,” said Samveg Saxena, a researcher at Lawrence Berkeley National Laboratory who worked on the study.

The research relies on forecasts for EV adoption in California, which predict there will be half a million fully electric vehicles and 1 million plug-in hybrid vehicles on the road by 2025.

Ambitious solar and storage project developer Lyon Infrastructure has teamed up with two major international energy and battery storage groups to pursue its portfolio of projects in Australia, and others overseas.

In joint announcement on Tuesday, Lyon says it has signed a “collaboration” agreement with Japan’s JERA and US-based Fluence to “identify and pursue utility-scale battery storage development and investment opportunities in Asia-Pacific markets.”

The agreement may provide renewed momentum for Lyon’s list of major solar and storage projects, which have attracted big headlines and publicity, but are yet to advance to contracting, financial close, or construction.

The three Australian projects flagged in this deal were due to begin construction in 2017 (see table below) and executive chairman David Lyon still promises that an announcement for a start in the first of those will be made in the first “within a few months”.

A legal battle with US solar giant First Solar over the details of one of Lyon’s projects appeared to take the wind out of its sails late last year.

But while the legal dispute is ongoing, Lyon’s David Green told RenewEconomy he is confident the company can move forward and it will not impact its projects.

Both JERA and Fluence are joint ventures created by some of the biggest energy players in the world.

JERA is joint venture of two major Japanese electricity companies, TEPCO Fuel & Power Inc and Chubu Electric Power Co, while Fluence is an equal joint venture of Siemens and AES that focuses on battery storage.

Together, the three groups say they will look at utility and industrial scale battery storage solutions in new projects and at existing renewable and thermal generation plants.

Lyon would be the project developer, JERA an investor, and Fluence the energy storage solution and service provider.

Top of the list in Australia are three long talked about projects that Lyon has been developing, and was talking about a year ago as on the point of development:

Most current solar energy systems utilize storage outside of the generators that create the power. In other words, two separate systems are required to ensure successful operation.

But experts from UT’s Cockrell School of Engineering have developed a way to integrate solar power generation and storage into one single system, effectively reducing the cost by an estimated 50 percent. The UT project will develop the next generation of utility-scale photovoltaic inverters, also referred to as modular, multifunction, multiport and medium-voltage utility-scale silicon carbide solar inverters.

Collectively, the combined technologies are known as an M4 Inverter – their main function being the conversion of the direct current output of solar panels to medium-voltage alternating current, which eliminates the need for a bulky and expensive low-frequency transformer.

Electrical and computer engineering professor Alex Huang, who directs the Semiconductor Power Electronics Center in the Cockrell School and works with the UT Center for Electromechanics, is the lead principal investigator for this DOE-funded project. He believes the M4 Inverter will create efficiencies in a variety of ways.

“Our solution to solar energy storage not only reduces capital costs, but it also reduces the operation cost through its multifunctional capabilities,” Huang said. “These functionalities will ensure the power grids of tomorrow can host a higher percentage of solar energy. By greatly reducing the impact of the intermittence of solar energy on the grid and providing grid-governing support, the M4 Inverter provides the same resilience as any fossil-fuel-powered grid.”

One such additional functionality is the ability to provide fast frequency control, which would prevent a solar-powered grid from experiencing blackouts on days when large cloud cover might obstruct solar farming.