Nova Scotia Power has established a pilot project that utilizes Tesla’s Powerpack 2 home batteries and their utility-grade Powerpack batteries to form an improved energy storage system for local wind power. Based in Elmsdale, the Intelligent Feed Project aims to bridge any gaps found in the electrical grid by installing Powerpacks where wind turbines are generating surplus energy. These batteries would allow power to be stored for later use, perhaps when there is a power outage or a windless day. While the Powerpack’s expansion into Nova Scotia isn’t quite as massive as its application in places like South Australia, this latest move demonstrates its potential to improve energy storage in power grids.

The Elmsdale battery station will serve 300 homes, 10 of which will have Tesla Powerpack 2 batteries. Partially funded by the Canadian government, the trial program will begin at the end of February and will continue until 2019. The physical infrastructure of Powerpacks will remain even after the trial has ended. If the trial is successful, Nova Scotia Power may decide to offer additional programs to local communities

Simply bringing the Powerpacks into the homes and neighborhoods of Elmsdale seems to be having a positive impact on engagement in clean energy infrastructure. “The Powerwall, that was something I hadn’t heard about,” said homeowner Mark Candow. “I was definitely intrigued.” The ease-of-installation and the interactive app provided by Tesla are certainly selling points for consumers. “The ability to monitor their home usage is really making them think more about how they’re using electricity in their home,” said smart grid engineer Rob Boone, “and I think it’s going to make them more energy efficient.”

Eandis is a distribution grid systems operator with activities in 229 cities and municipalities throughout Flanders in Belgium, responsible for 2.7 million electricity connections. Eandis recently added some 375 kWp rooftop solar power to its logistical center in Lokeren. To match the intermittent solar energy production with its own operations, it is now implementing Alfen’s battery energy storage system called TheBattery. TheBattery contributes to the increasing electrification of the site, enabling the shift from fossil fuel powered machinery and vehicles towards electricity as source of energy.

Jean Pierre Hollevoet, Director Asset Management and Supply Chain at Eandis comments: “With the new energy storage system of Alfen, we will be able to optimize self-consumption of the solar energy in our facilities, which is an important new step towards an energy neutral and sustainable distribution center. Alfen has an 80-year track record and deep technical knowledge of developing complex battery storage systems. In addition, we anticipate that more and more customers, connected to our electricity grid, will implement energy storage systems in the future. We want to be prepared for the incorporation of such systems in our grid and therefore we want to gain experience on manageability, cost-of-ownership and impact on operational efficiency of such a storage system.”

Energy storage system TheBattery

Alfen supplies a 140kW energy storage system that will be connected to Eandis’ logistical center. Alfen also delivers and implements the remote management and control of the system and provides a platform which enables Eandis to use the system for optimizing self-consumption of renewable energy and voltage control. Yves Vercammen, sales manager for Alfen in Belgium, comments: “We welcome this opportunity to use our storage system and decades of power grid experience in this project. The collaboration with Eandis shows that we are operating at the heart of the energy transition with a unique integrated offering dedicated to enable the energy grid of the future. This project demonstrates the increasing demand for decentralized renewable energy solutions that require smart energy solutions.”

The storage system will be operational in Q1 2018.

In order to power entire communities with clean energy, such as solar and wind power, a reliable backup storage system is needed to provide energy when the sun isn’t shining and the wind doesn’t blow.

One possibility is to use any excess solar- and wind-based energy to charge solutions of chemicals that can subsequently be stored for use when sunshine and wind are scarce. At that time, the chemical solutions of opposite charge can be pumped across solid electrodes, thus creating an electron exchange that provides power to the electrical grid.   The key to this technology, called a redox flow battery, is finding chemicals that can not only “carry” sufficient charge, but also be stored without degrading for long periods, thereby maximizing power generation and minimizing the costs of replenishing the system. For more details see the IDTechEx report on redox flow batteries.   University of Rochester researchers, working with colleagues at the University at Buffalo, believe they have found a promising compound that could transform the energy storage landscape.

In a paper published in Chemical Science, an open access journal of the Royal Society of Chemistry, researchers in the lab of Ellen Matson, assistant professor of chemistry, describe modifying a metal-oxide cluster, which has promising electroactive properties, so that it is nearly twice as effective as the unmodified cluster for electrochemical energy storage in a redox flow battery.

The cluster was first developed in the lab of German chemist Johann Spandl, and studied for its magnetic properties. Tests conducted by VanGelder showed that the compound could store charge in a redox flow battery, “but was not as stable as we had hoped.”

However, by making what Matson describes as “a simple molecular modification”— replacing the compound’s methanol-derived methoxide groups with ethanol-based ethoxide ligands—the team was able to expand the potential window during which the cluster was stable, doubling the amount of electrical energy that could be stored in the battery.

As US president Donald Trump throws his support behind “beautiful clean coal,” the American state of Arizona — a Republican Party stronghold — is poised to take the lead on energy storage in the country as it tosses up whether to impose an 80% clean energy target by 2050.

The proposed clean energy overhaul, called the Energy Modernisation Plan, would require an impressive 3GW energy storage to be installed by 2030, meaning it would overtake California and New York for the biggest storage mandate in the country.

The proposal was put forward recently by the Arizona Corporation Commission’s Andrew Tobin as a way to both decarbonize the state’s power supply, and to meet its peak power demand in a cheaper and cleaner fashion.

The plan calls for the state’s investor-owned utilities to source 80% of their electricity from a mix of renewable and nuclear energy by 2050 and deploy 3,000MW of energy storage by 2030, along with reforms to boost energy efficiency, electric vehicles, and biomass.

And the plan’s proposed “Clean Peak Standard” would require utilities to deliver an increasing portion of their renewable energy during peak electricity demand hours, thus encouraging the deployment of energy storage capacity.

As Greentech Media reports, the ambitious proposal would “leapfrog” Arizona ahead of California and New York, “which have dominated the grid modernization discussion so far,” both with 50% by 2030 renewable energy targets, and storage targets of 1,300MW and 1,500MW respectively.

It also demonstrates a similar state vs federal government divide as we have seen play out in Australia, with states leading on the shift to decentralized, renewable energy, while conservative national leaders cling desperately to coal and other centralized fossil fuel generation sources.

“We’re not trying to get on the train; we’re trying to be the engine in the train,” Tobin told Greentech Media. “This is Western people doing things and setting lofty goals and reaching them.”

But as well as shifting the state’s focus to renewable energy and storage, a major aim of the plan would also be to shift the focus away from gas generation, which, according to UtilityDive, Arizona utilities have been doubling down on.

“What this plan is saying is we aren’t going to build our future on natural gas — the backbone of the system over the next 40 to 60 years will not be gas,” said Lon Huber, a consultant who worked to craft the original Residential Utility Consumer Office RUCO) proposal.

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Energy storage has frequently been cited as the critical missing link in an electric infrastructure designed to maximize the benefits of cheap, renewable energy.  Because energy from the sun and the wind is inherently intermittent, it has not been able to satisfy a round-the-clock need for electricity.  And in many places we’ve built more renewable capacity than we can use, when the sun is shining, or when the wind is blowing.  For example, in sun-soaked California and the West, electric grid operators have recently been confronted by the challenge of “over-generation” during peak solar hours of the day, which can result in the curtailment of solar generation to avoid overloading the grid with electrons.  Similarly, in Texas, so much wind blows at night that the electricity off-takers can sometimes get paid through “negative” power prices to use the wind power.

For California, a state that has set its electric grid on a path toward 50% renewable by 2030 (SB 350 (De León)), and one that is considering a 100% RPS by 2045 (SB 100(De León)), the question of energy storage has taken on a practical significance.  And regulators at the federal and state level have been quite busy taking down barriers that have made the increased adoption of energy storage resources impracticable.

Today Bud Earley of Covington blogged about the recent approval at the Federal Energy Regulatory Commission (FERC) of its 2017 electric storage rulemaking.  That rule set out broad market criteria for the participation of energy storage resources in regional electricity markets, and left the question of distributed energy resources (DERs), for a later date.

Given its innovative policy work on both fronts, California is a natural market to look to for policy models that may be relevant beyond the California ISO (CAISO).  In California, state regulators have already begun seeking comment and setting rules for the participation of both DERs and energy storage in the market.  The CAISO has begun, for example, reviewing applications from some companies, including investor-owned utility companies, to seek approval as distributed energy resource providers (DERPs); and the CAISO has sought and received approval from FERC to seek tariff proposals that allow DERPs to aggregate and sell resources in the grid.  And with respect to energy storage, the state regulator — the California Public Utilities Commission (CPUC) — recently issued a decision for new “multiple-use” applications for energy storage, which allow storage providers to “stack” various services.

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Cheap energy storage, long-hailed as renewable energy’s younger cousin that once of age would create a dynamic duo strong enough to upend the electricity system as we know it got a steroid shot this week when FERC announced that it was going to let energy storage operate in the wholesale markets as both a buyer and a seller.

While this development plays to storage’s benefit, the market (at current prices) is still relatively small. For energy storage to make a big play, costs still needs to come down by about half and the market itself might have to change.

In the U.S. most energy storage comes from pumped hydro facilities, but these systems require large amounts of co-located land, elevation, and water. Batteries have been (or will be) built in both Texas and Arizona in order to defer expensive transmission line upgrades.

But battery prices are now declining to the point where they are starting to move into new markets. Tesla’s 100MW/129MWh battery in South Australia appears to be taking full advantage of market price fluctuations and helping the grid ride through multiple coal plant trips this (Australian) summer.

In the U.S., Tucson Electric Power recently entered into a power purchase agreement with a 100MW solar + 30MW/120MWh battery project for about 4.5 cents/kWh and Arizona Public Service (APS) just this month contracted with First Solar to build a 65MW solar + 50MW/135MWh project with the stipulation that its capacity be available summer afternoons from 3-8pm. At other times, the battery is free to provide other services to the market. Both of these projects benefit from the fact that, if a battery charges mainly from solar, it is eligible for the same 30% investment tax credit as the solar itself.

Battery energy storage is starting to target peak demand hours. Peak demand usually happens on summer afternoons (both north and south) when people are getting home from work and air-conditioners are straining to keep homes cool. There are also winter peaks for cold weatherwhich can occur on cold mornings when people are just waking up and getting ready for the day.

In the U.S. we usually meet our peak demand with natural gas combustion turbines. These types of power plants are basically jet engines bolted to the ground and hooked up to a generator. They can start and ramp their output quickly, making them good for following swings in load. Some areas of the country utilize diesel engines as peakers and lately natural gas internal combustion engines (diesel engines reconfigured to run on natural gas) are frequently deployed.

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The automotive industry increasingly is looking toward electrification as a solution to meet changing emissions standards across the globe and as regulations become stricter, they are taking these initiatives even further.

While automakers traditionally have approached vehicle electrification in micro-hybrid vehicles through start-stop technology, which shuts off the engine when the car comes to a stop, the industry is evaluating new electrification strategies to meet future carbon-dioxide emissions standards while increasing performance and features.

Several of these new technologies will be adopted in mild-hybrid vehicles where an electric motor assists the combustion engine during short accelerations or braking and by allowing it to turn off for longer periods of time while the car is coasting. As a consequence, the combustion engine potentially can be downsized to significantly reduce emissions without compromising performance.

To push fuel economy even further, mild-hybrid vehicles often combine the efficiency advantage of an electric turbocharger with an electric braking system for recuperation.

In addition, premium vehicles will continue offering a wide variety of new, innovative electric features that provide comfort for the driver and the passengers, such as electric active-roll control, electric power steering and electro-turbocharging. Collectively, these features have demanding power requirements and each requires frequent, quick, high-power charge and discharge events, which is pushing energy-storage engineers to revolutionize the board-net strategy for the platform.

The Limits of Lead-acid and Lithium-ion Batteries

Traditionally, lead-acid batteries have been used in automotive applications due to low cost and simple monitoring. But, when exposed to high discharge rates or rapid cycling applications, those batteries experience accelerated aging, which automakers traditionally have overcome by oversizing the battery. However, using larger lead-acid batteries cannot reasonably compensate for peak power demands that can be up to 10 times higher than traditional architectures, while still meeting strict weight and size objectives.

In recent years, lithium-ion batteries have been increasingly adopted by the automotive industry because of their improved power and energy density performance compared to lead-acid batteries. Although the technology has made significant performance improvements, their low temperature profile and sophisticated battery-management system with heating and cooling remain a constraint to achieve optimal performance and lifetime.

Solving Batteries’ Shortcomings With Ultracapacitors

Because of batteries’ high-power performance limitations, ultracapacitors are gaining traction as an alternative energy-storage technology. There are two possible ways to integrate ultracapacitors to the energy-distribution network: as exclusive energy storage in a sub-network, also called an island solution; and in parallel with batteries, creating a hybrid energy-storage system.

While the first topology has been designed multiple times to assist high peak-power loads of a single function, hybrid energy storage is gaining traction in combining the high-energy density of the battery with the high-power density of the ultracapacitor.

The Federal Energy Regulatory Commission has passed a rule that will open U.S. wholesale energy markets to energy storage on an equal footing with generators and other grid resources. But it hasn’t yet figured out how to address the same challenge for distributed energy resources.

On Thursday, FERC commissioners unanimously approved the final version of a rule, first proposed in November 2016, designed to “remove barriers to the participation of electric storage resources” in the wholesale energy markets that make up about three-quarters of the country’s electricity supply.

Within the next nine months, each of these regional transmission organizations (RTOs) and independent system operators (ISOs) will be required to come back with a plan for revising its tariffs to establish a participation mode for energy storage, “consisting of market rules that, recognizing the physical and operational characteristics of electric storage resources, facilitates their participation” across the range of markets that make up a regional transmission grid.

That’s a much broader set of opportunities than those currently available to large-scale batteries, pumped hydro systems, thermal energy storage and other types of energy storage now participating in ISO and RTO markets. To date, those have been limited in geography and in type, with the vast majority of storage playing in fast-responding frequency regulation markets, and with viable markets in only a handful of jurisdictions.

This biggest, mid-Atlantic grid operator PJM’s frequency regulation market, has also became the largest U.S. market for energy storage, with about 250 megawatts of cumulative deployments since 2013 — although it’s largely tapped out at present and suffering from some of the side effects of its own success.

FERC’s new rule will expand the scope of energy storage’s participation beyond frequency regulation and into larger ancillary services and wholesale energy and capacity markets, and for all ISOs, not just the handful like PJM and California grid operator CAISO that have taken the lead on the matter.

ISOs and RTOs still have a year to implement these future energy storage market participation rules. But when they do, they will likely become one of the largest opportunities for energy storage in the country, noted GTM Research’s Ravi Manghani. “This opens the floodgates for storage participation,” he said.

Energy storage and clean energy groups also praised the decision, noting the benefits that grid-scale batteries are already providing in the limited applications where they’re cost-effective, and hold promise for much broader applications as battery prices continue to fall in years to come.

FERC’s commissioners concurred in their written statements. Commissioner Cheryl LaFleur, a Democrat, called storage a “Swiss army knife” in its ability to provide energy alongside variable renewable generation, provide frequency regulation and other ancillary services, and help defer distribution and transmission needs.