Ice storage has largely proven its worth, with projects utilizing cheaper energy to freeze a solution that can be later used for cooling during times of peak demand.

Viking’s test at the Dreisbach Enterprises’ frozen food distribution center showed a significant drop in weekly energy use and an even greater drop in peak refrigeration load.

In a sign of the increasing interest in thermal energy storage, last year, Massachusetts tapped Genbright and Ice Energy for a $1.5 million grant to utilize thermal energy storage at residential sites, and for peak demand reductions. In California, Ice Energy and NRG Energy partnered on 1,800 Ice Bear 30 storage solutions to commercial and industrial buildings in Orange County, Calif., as part of Southern California Edison’s storage procurement efforts.

Viking’s system is a bit different, it says, utilizing a phase change material that it describes as “a substance with
a high latent heat of fusion which remains near a constant temperature while storing and releasing large amounts of energy.”

Transitioning from solid to liquid, Viking says the phase change material “absorbs up to 85% of heat infiltration and maintains more stable temperatures to better protect food product.”

The result at the Dreisbach Enterprises’ frozen food distribution center was a 20% decrease in weekday energy use, which the M&V report said was countered somewhat by a 5% increase in off-peak weekend consumption, in order to fully recharge the TES.

The net result, Viking’s study concluded, was a 13% reduction of energy consumption for the entire facility each week. More importantly, the TES lowered peak refrigeration load by 251 kW, a 29% reduction for 13 hours each day.

The study “demonstrates that cold storage operators can safely reduce energy costs and utilities can significantly lower demand on the electrical grid during peak periods to defer costly infrastructure investments,” Collin Coker, vice president of sales at Viking, said in a statement.

Viking said it is now in talks to deploy additional TES technology Dreisbach Enterprises facilities.

Energy storage is the key to renewables. A decade ago, solar panels could make electricity during the day, which was great. But in most parts of the world, the highest demand for electricity occurs in the late afternoon and early evening — times when solar panels produce little electricity. Wind turbines are wonders of modern engineering but of little use if there is no wind to turn their blades.

Being able to store electricity now for use later is what makes renewable energy capable of providing reliable baseload power at all times of day or night. How long that storage ability lasts is one of the primary ways that energy storage systems are classified. Cost, of course, is another.

It is one thing to store electricity for a few hours; quite another to store it for days or weeks at a time. The ultimate goal of energy storage is systems that can store energy for entire seasons, so Londoners can heat their homes in the winter with electricity stored in the summer.

Batteries today cost around $280 to $350 per kilowatt hour and are just at the threshold of being able to store electricity for several hours or perhaps an entire day. The costs are coming down, with some industry experts predicting prices will fall below $100 per kWh in the future, but that price is still years away. Batteries also have a useful life — typically 20 years. After that, they need to be replaced.

Swiss startup Energy Vault has a different idea. According to Quartz, it plans to construct energy storage systems that use concrete blocks. A 400′ tall crane with 6 arms uses excess electricity to power electric motors that lift and stack concrete cylinders weighing 35 metric tons each all around it. Later, the crane lowers them back to the ground, generating electricity during the descent. Think of it as a regenerative braking system that operates vertically rather than horizontally. The current cost of an Energy Vault system is around $150 per kWh.

Minister for Energy Dr Megan Woods attended an event to officially inaugurate the first grid-scale battery energy storage system in New Zealand, hosted by energy retailer and project owner Mercury Energy.

The project, based around a Tesla Powerpack 2 battery system was revealed to be under development in January this year. Energy-Storage.news reported at the time that the 1MW / 2MWh of Powerpacks is connected to existing pumped hydro facilities in South Auckland and used by Mercury’s R&D centre as part of a trial of scalable grid-connected batteries.

Back in January, Mercury said battery capacity at the installation itself could be added to at a later date, and that the system, with a cost of close to NZ$3 million (US$2.01 million), would trial the redispatch of electricity generated by hydro as well as the possibility of using the Powerpacks in energy trading markets. A Mercury announcement this morning also said the project could be used to investigate the redispatch of geothermal energy.

“We see battery storage as playing an increasingly important role in providing a reliable supply of electricity in New Zealand, as we increase our reliance on wind and solar to generate our electricity,” John Clarke, general manager at grid operator Transpower, said.

“We look forward to continuing to work with Mercury throughout the trial and gather key learnings to enable the transition to New Zealand’s sustainable energy future”.

Energy industry experts speaking at the MEGA Symposium in Baltimore, Maryland, on August 21 agreed that storage is becoming more important to the overall mix of U.S. power sources. They also said utility-scale storage solutions remain “years away,” even as technology advancements in battery systems occur more rapidly.

Panelists at the session entitled “The Transformation of the Power Industry and the Role of Energy Storage,” representing utility, finance, research, and coal industry interests, said storage has proved its mettle when it comes to energy, but there is no “one-size-fits-all” solution when it comes to deploying storage assets across the power grid.

“Energy storage can transform how we make, move, and sell electricity across the grid,” said Steve Baxley, manager for renewables, storage, and distributed generation for Southern Co. “It can transform the whole marketplace. It’s a capacity resource, a flexibility resource, and reliability and resiliency resource, and a voltage and power quality resource. But there are a lot of emerging questions in this field. How do we implement [storage]? How do we interconnect to the grid?”

The experts said storage is valuable to provide backup power and balance intermittent sources of power on the grid, such as solar and wind. They also said it’s not a substitute for baseload power during extreme events such as the “bomb cyclone” that hit much of the eastern U.S. in early 2018, bringing frigid temperatures and icy precipitation.

“During the bomb cyclone, coal provided about 55% of the generation across six [independent systems operators],” said Peter Balash, senior economist for the Department of Energy’s (DOE’s) National Energy Technology Laboratory (NETL). “Without coal, we would have had a [power] shortfall in PJM,” the regional transmission organization (RTO) that serves all or part of 13 midwestern and eastern states. “The second largest [amount of generation] came from fuel oil. Constraints in the pipeline system led to price spikes in natural gas,” and those constraints also meant the supply of gas could not keep up with demand, particularly in the Northeast.

“Increases in power prices during the event offset the lower price of natural gas,” Balash said, noting the extreme weather event showed how generators don’t want to rely on just one energy source to maintain reliability and resilience on the grid. He said that while energy storage facilities often are located near major population centers, “less than 40% of [those] are capable of producing more than 1 MWh of power”—not nearly enough to keep up with the demand for heat during the January event, or the polar vortex event that struck much of the same area in 2014.

Deck Slone, senior vice president of strategy and public policy for Arch Coal, noted the U.S. coal fleet has lost “about 30% of its generation capacity” over the past decade, which he said puts baseload power at risk. “It’s going to take a while to get to large-scale energy storage,” to a level that could begin to replace the lost capacity, he said.

Energy storage is the key to renewables. A decade ago, solar panels could make electricity during the day, which was great. But in most parts of the world, the highest demand for electricity occurs in the late afternoon and early evening — times when solar panels produce little electricity. Wind turbines are wonders of modern engineering but of little use if there is no wind to turn their blades.

Being able to store electricity now for use later is what makes renewable energy capable of providing reliable baseload power at all times of day or night. How long that storage ability lasts is one of the primary ways that energy storage systems are classified. Cost, of course, is another.

It is one thing to store electricity for a few hours; quite another to store it for days or weeks at a time. The ultimate goal of energy storage is systems that can store energy for entire seasons, so Londoners can heat their homes in the winter with electricity stored in the summer.

Batteries today cost around $280 to $350 per kilowatt hour and are just at the threshold of being able to store electricity for several hours or perhaps an entire day. The costs are coming down, with some industry experts predicting prices will fall below $100 per kWh in the future, but that price is still years away. Batteries also have a useful life — typically 20 years. After that, they need to be replaced.

Swiss startup Energy Vault has a different idea. According to Quartz, it plans to construct energy storage systems that use concrete blocks. A 400′ tall crane with 6 arms uses excess electricity to power electric motors that lift and stack concrete cylinders weighing 35 metric tons each all around it. Later, the crane lowers them back to the ground, generating electricity during the descent. Think of it as a regenerative braking system that operates vertically rather than horizontally. The current cost of an Energy Vault system is around $150 per kWh.

The entire system can store 20 MWh of electricity. Batteries can store that same amount of electricity in a smaller space but have a useful life of about 20 years. There is little long term data available about how utility scale batteries might degrade over time, but extrapolating from electric car experience suggests a fall-off in capacity of between 10% and 20% after 20 years. Energy Vault claims its system has an overall efficiency of 85% versus 90% for a typical battery storage installation and has a useful life of at least 30 years with little to no degradation in performance over time.

The company uses off the shelf components that have been manufactured by ABB and Siemens for decades, so equipment costs are kept to a minimum. Oddly enough, the biggest expense is for the concrete. Here the company has thought way outside the box — or the concrete block — and devised a way to make concrete for one sixth the usual cost. They mix cement with materials cities often pay to get rid of, like gravel or building waste.

Known historically for its oil and in the present day for deploying large amounts of wind energy and latterly for deploying batteries at wind farms, the US state of Texas is less well known for solar-plus-storage projects.

UK-headquartered multinational developer and EPC (engineering, procurement and construction) provider RES Group has just announced however that it has been contracted by Texas utility CPS Energy to execute a 5MW(AC) solar project co-located with 10MW / 10MWh of lithium-ion battery energy storage.

The combined system will be capable of capturing peak solar production around the middle of the day, to be stored and injected into the grid in the late afternoon and evenings when consumer demand has its own peak and solar production has tailed off for the day.

While the overall system size is relatively small, RES (Renewable Energy Systems) said that the distributed solar capacity is paired with a battery system that will be “strategically sized and configured” to optimise its effectiveness. RES also said that this solution could be scalable for use in other projects, touting the fact that it will help meet peak demand with lower emissions and more flexibility than existing and available balancing from fossil fuel generators.

The project will be located at what appears to be a former industrial plot of land in San Antonio now belonging to Southwest Research Institute (SwRI), with RES having been selected through a competitive process. The company will perform EPC tasks and carry out maintenance with construction scheduled to begin in October for the start of commercial operation by May 2019. SwRI will use its hosting of the project as an opportunity to “showcase” it.

“As beneficial as the site will be to the city’s energy future, SwRI will also benefit by leveraging the facility to become even more active in the grid-scale energy storage industry, and to work with battery suppliers and component manufacturers,” SwRI powertrain engineering division VP Daniel Stewart said.

Our clean energy future will require more energy storage to help ensure the lights stay on when the sun isn’t shining or the wind isn’t blowing. Your shiny new electric vehicle may also become an important type of battery for our power grid.

New research shows that leveraging the storage potential in electric vehicles, instead of just investing in stand-alone stationary batteries, could save utility customers billions of dollars, while also encouraging drivers to ditch gasoline. A study recently published by researchers at the Lawrence Berkeley National Laboratory (LBNL) shows that the electric vehicles (EVs) expected in California in 2025 could be used to meet the majority of the Golden State’s energy storage mandate that calls for 1.3 gigawatts (GW) of battery capacity by 2024. In fact, EVs can accomplish this both reliably and at about one-tenth the cost of stationary energy storage approaches. This level of storage could power nearly one million average homes, at least for a short while.

That EVs can be this valuable to the grid is a hugely significant finding.

One third of California’s electricity already comes from renewable resources like wind and solar, and the state is on track to meet its goal of generating at least half of its electricity from renewable resources by 2030. And if California Senate Bill 100becomes law this year, the goal for 2045 would be for 100 percent of California’s electricity to come from renewable or zero-carbon sources.

That’s great news for cleaning up our electricity supply, but increasing our reliance on variable resources like wind and solar generation necessitates overcoming a different set of challenges to manage the electrical grid. Thankfully, we already have proven ways to address these potential issues, including better weather forecasting, sharing power across broader geographical areas, and, most pertinent to this blog, the prudent use of stand-alone batteries and EV batteries.

The challenge of integrating variable resources like wind and solar can be depicted by the lovingly-termed “duck curve.” At its core, the “duck curve” depicts the large swing in net electricity demand and supply that occurs through the day as the sun moves across the sky or wind patterns change, and electricity supply is needed from non-renewable resources. This has implications for how grid operators must manage the various resources to ensure reliability. The graph below takes a typical spring day (March 31) and plots out what the “net load” would be from 2012 to 2020. Renewable electricity is assumed to satisfy the power demand first, and the leftover, unserved demand is termed “net load.”

A week ago, we wrote about two bills which are pending in the California legislature that could re-shape the state’s grid. It turns out that we missed one.

We had given up on SB 700, the bill that would extend the state’s popular Self Generation Incentive Program (SGIP) for another five years, after it languished for weeks in the Appropriations Committee of the California Assembly this summer. But as it turns out, the bill was not yet dead.

Following a rally by an estimated 200 solar workers on August 14, SB 700 was passed 12-5 out of the Assembly Appropriations Committee on August 16, and is now expected to go to the floor of the Assembly, its final stop before the desk of Governor Jerry Brown (D).

California Solar and Storage Association (CALSSA), which sponsored the bill and promoted the Tuesday rally, says that SB 700 is of “critical” importance in meeting the state’s clean energy goals as well as protecting tens of thousands of jobs in the residential solar industry.

“SB 700 will do for storage what SB 1 did for solar over a decade ago, namely create a mainstream market by driving up demand and driving down costs all while creating jobs and clean energy choices for consumer,” stated CALSSA Executive Director Bernadette Del Chiaro in a press statement.

While energy storage is being promoted in California through a variety of policies including mandatory procurement by utilities under AB 2514, many of these policies lean towards supporting large-scale storage. By contrast, SGIP has been a key subsidy for behind-the-meter installations, but will run out in 2020.

Current law authorizes state regulators to collect up to $166 million per year from the state’s big three investor owned utilities through the end of 2019 for this program, and under SB 700 this would be continued through the end of 2024, meaning up to $700 million in additional storage incentives to continue the program through the end of 2025.

Storage as a solution to TOU rates

In a press statement for the Tuesday rally, CALSSA specifically mentions the shift to time of use rates for residential solar as a threat to California’s solar workers. These rates have continually been pushed to later in the day by utilities, disadvantaging residential solar.

Thanks to the modern electric grid, you have access to electricity whenever you want. But the grid only works when electricity is generated in the same amounts as it is consumed. That said, it’s impossible to get the balance right all the time. So operators make grids more flexible by adding ways to store excess electricity for when production drops or consumption rises.

About 96% of the world’s energy-storage capacity comes in the form of one technology: pumped hydro. Whenever generation exceeds demand, the excess electricity is used to pump water up a dam. When demand exceeds generation, that water is allowed to fall—thanks to gravity—and the potential energy turns turbines to produce electricity.

But pumped-hydro storage requires particular geographies, with access to water and to reservoirs at different altitudes. It’s the reason that about three-quarters of all pumped hydro storage has been built in only 10 countries. The trouble is the world needs to add a lot more energy storage, if we are to continue to add the intermittent solar and wind power necessary to cut our dependence on fossil fuels.

A startup called Energy Vault thinks it has a viable alternative to pumped-hydro: Instead of using water and dams, the startup uses concrete blocks and cranes. It has been operating in stealth mode until today (Aug. 18), when its existence will be announced at Kent Presents, an ideas festival in Connecticut.

On a hot July morning, I traveled to Biasca, Switzerland, about two hours north of Milan, Italy, where Energy Vault has built a demonstration plant, about a tenth the size of a full-scale operation. The whole thing—from idea to a functional unit—took about nine months and less than $2 million to accomplish. If this sort of low-tech, low-cost innovation could help solve even just a few parts of the huge energy-storage problem, maybe the energy transition the world needs won’t be so hard after all.

Independent energy storage solutions developer Convergent Energy + Power (Convergent) has commissioned North America’s biggest behind-the-meter energy storage system in Sarnia, Ontario.

The system, with a storage capacity of 10MW/20 MWh, will help Convergent reduce Global Adjustment charge for an industrial customer.

Global Adjustment, which accounts for nearly 70% of the average industrial electricity bill in Ontario, encourages large electricity users in the region to minimise their power consumption during the most expensive grid periods.

Convergent CEO Johannes Rittershausen said: “This system combines cutting-edge technology and design with Convergent’s unparalleled peak dispatch services, creating maximum savings for our customer.

“Commissioning the biggest behind-the-meter energy storage system in North America would not have been possible without a forward-thinking customer and the innovation of our supplier, IHI.”
Apart from delivering the energy storage system, Convergent has also contracted IHI Energy Storage to provide operations and maintenance services and a capacity guarantee for the system.

The system, which is capable of powering an electric bullet train for 500 miles, has already reached this summer’s peaks causing no interruption to the customer.

With the battery system, commercial and industrial customers can save up to 40% on their electricity bills.

Convergent is said to have become the largest operator of energy storage in the Canadian province with 26MW of energy storage assets. IHI Energy Storage has another 21MW contracted in the region.