DNV GL, an Oslo, Norway-headquartered global quality assurance and risk management company that also acts as a certification body, handed the certificate to the Spanish conglomerate at WINDPOWER 2018 in Chicago this May. DNV GL’s certificate demonstrates the safety, performance, and reliability of ACCIONA’s hybrid plant for storing electricity in batteries as part of a grid-connected wind farm at Barásoain in Navarra, northern Spain.

The Barásoain plant has a storage system that consists of two batteries that are located in separate containers. One is a fast-response battery of 1 MW/0.39 MWh, which is capable of maintaining 1 MW of power for 20 minutes, and the other is a slower-response battery, though it has “greater autonomy” of 0.7 MW/0.7 MWh, maintaining 0.7 MW for 1 hour, said ACCIONA. Both employ Samsung SDI lithium-ion technology. The energy storage technology is connected to a single 3-MW AW116/300 wind turbine that uses ACCIONA Windpower (Nordex Group) technology. According to ACCIONA, the wind turbine is one of five that make up the Experimental Wind Farm at Barásoain, which it has operated since 2013. ACCIONA manages the entire system using control software it developed in-house. The system is monitored in real-time by the company’s Renewable Energies Control Center (Figure 4).

The certification milestone is important because while energy storage technologies are increasingly being deployed along with renewable projects at a grid-scale, a comprehensive standard that guarantees their safety and reliability is rare. The certification is designed to provide more certainty to industry, including technology designers and manufacturers, as well as auxiliary backers like investors, insurers, and government authorities, which often seek information about risk mitigation and cost controls, particularly for fledgling energy storage projects.

“Certifying new systems like ACCIONA’s grid-scale storage plant demonstrates that pioneering projects like this are meeting the required safety, performance and reliability standards and providing the industry with confidence in the quality of emerging new technologies,” said Kim Mørk, executive vice president, Renewables Certification at DNV GL.

According to Carlos Albero, global finance segment leader of DNV GL’s energy division, as well as providing a quality benchmark, the certification verifies ways a hybrid renewables-storage project can make money. “We’re not speaking about the batteries themselves,” he explained to POWER. “You are integrating the wind turbines with the storage platform, and at the end of the day, they have to work together.” Hybrid projects have the benefit of providing revenue streams from grid-related services, such as from frequency and voltage regulation. “So, these are the kinds of revenue considerations that will need to support storage projects in the future,” he said.

Residential solar Tesla‘s (NASDAQ:TSLA) Powerwall is the best-known energy storage device, but Sunrun (NASDAQ:RUN), SunPower(NASDAQ:SPWR), and Vivint Solar (NYSE:VSLR) are entering the market as well, and they’re seeing some signs of success early in 2018.

What’s great about energy storage for solar installers is that it’s incremental revenue that leverages existing marketing and sales expenses. And it could help make solar more attractive to customers in states that have made it more difficult to justify solar economically.

The solar industry’s next growth product

Sunrun has given the most information about how many energy storage systems it’s selling with residential solar systems in the U.S., and the early numbers are impressive. During the company’s first-quarter 2018 conference call, CEO Lynn Jurich said, “We launched Brightbox in Massachusetts less than three months ago, and already nearly 10% of the time customers we sell to directly are opting to add a battery.”

Sunrun doesn’t disclose the revenue or margin per energy storage system, but according to EnergySage, there’s at least $5,000 of incremental revenue per energy storage system and sometimes over $10,000 of added revenue.

Since Sunrun built solar systems for 45,000 customers in past year, that’s a potential for $225 million of additional revenue each year. It’s unlikely the solar industry will ever reach 100% energy storage penetration, but even 10% to 50% of the market adopting energy storage could have a big impact on financials.

Sunrun isn’t alone in energy storage

Tesla was once the leader in solar energy storage, but its solar business is shrinking, and storage projects have been shifted to the utility-scale market. If you want to invest in a stock with residential energy storage growth, it sounds crazy to say it, but Tesla isn’t the right pick.

SunPower says it is now including energy storage with about 30% of commercial solar installations and expects to use the same strategy in residential energy storage products as they roll out later this year. The hope is that being a leader in commercial storage will give the company a leg up in residential energy storage, although it’s only in early stages of launching the product right now.

Vivint Solar is at least a few months behind Sunrun and SunPower after losing its battery partner Mercedes-Benz, which dropped out of residential energy storage earlier this year. The company is now selling the same LG Chem batteries that Sunrun installs, but isn’t yet selling in most markets and doesn’t have the same experience in energy storage controllers, which is ultimately what creates value for customers. Vivint has upside in residential energy storage, but Sunrun and SunPower are the two leaders right now.

NV Energy announced Thursday it has contracted for more than 1 gigawatt of new solar energy and 100 megawatts of battery energy capacity, in a resource plan that’s still subject to regulatory approval and hinges on the outcome of a high-profile ballot measure.

The utility signed power purchase agreements for six new solar energy projects and three related battery storage projects, selected through a competitive solicitation initiated in January of this year. All projects are expected to be complete and serving customers by the end of 2021 – if the Public Utilities Commission of Nevada approves the plan.

“The six new projects position NV Energy to keep its commitment to double renewable energy by 2023 and, importantly, by diversifying our state’s electricity generation portfolio, will reduce the costs to serve customers,” said CEO Paul Caudill, in a statement.

The clean energy expansion plan also represents a step forward in the company’s long-term goal of serving Nevada customers with 100 percent renewable energy, he said. NV Energy claims the direct investment in Nevada’s economy will be greater than $2 billion, and will create 1,7000 construction jobs and 80 permanent, long-term jobs.

Work on the resource planning effort began shortly after Nevada’s 2017 state legislative session ended, “and demonstrates that we are navigating the uncertainties in the current market, given Question 3 on the statewide ballot,” Caudill added.

Question 3, also known as the Energy Choice Initiative, would require the Nevada State Legislature to establish “an open, competitive retail electric energy market that prohibits the granting of monopolies and exclusive franchises for the generation of electricity.”

The Energy Choice Initiative first appeared on the November 2016 ballot as an initiated constitutional amendment, and was approved. In Nevada, constitutional amendments must be approved in two even-numbered election years in order to take effect. Mounting support for clean energy in the state has put enormous pressure on NV Energy to take action.

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.