As such, it is seen as an essential complement to variable renewable-energy sources such as wind and future expectations for storage are high. The US Department of Energy (DoE), for example, has a budget of $20 million for storage research this financial year. Industrial research funding probably matches or exceeds this.
Study after study proclaims the virtues and promise of electricity storage. Analysts Pike Research have suggested a worldwide market of $20-25 billion a year
by 2020. Its energy storage tracker published in July found that there is now 157,162MW of energy storage installed globally (see graphic overleaf).
The total number of energy-storage projects worldwide rose from 600 to 649 in the first half of 2012, an 8% increase, according to Pike Research. The majority of these projects — 514 — are already deployed, the are merely announcements.
"Considerable momentum is building behind newer energy-storage technologies, such as advanced batteries, particularly as the renewable-energy community embraces storage as a means of mitigating risks associated with variable power-generations resources," says Pike Research analyst Brittany Gibson.
The positive expectations stem from the fact that storage costs are likely to come down and, with increasing amounts of wind and solar energy on electricity networks, the business case for system storage is likely to become stronger. This is because more wind means greater demand for short-term operational reserve, and increasing demand tends to be accompanied by higher prices.
Anthony Price, director of UK trade body the Electricity Storage Network, explains that there are various tools to deal with increased variability in supply and demand on an electricity system, including responsive generation, demand-side management, interconnectors and storage.
"Storage can both absorb and eject energy so uniquely can participate in both demand and supply – it is the glue that holds the smart grid together," he says.
However, a report from global power company Alstom for the DoE last September pours doubt on the assumption that storage is essential on systems with high amounts of renewables. Alstom surveyed utilities and grid operators and found that more than 60% of respondents ranked the impact of energy storage on wind integration as high.
But the report warns: "This ranking occurs despite the fact that there are no known study results that suggest energy storage is absolutely needed to integrate large amounts of wind generation in existing power systems."
Is it cost-effective?
The high expectations for storage may stem from the fact that systems are likely to develop in the future and possibly become cost-effective in the next 20 years, the report suggests.
Cost effectiveness is key to the debate. Electricity delivered from a storage system will only be economic if the value of the energy that is sold is greater than its final cost. As with any other generation technology, the electricity cost is made up of a fuel cost, which in this case is the cost of the electricity used for charging; a capital cost; and operation and maintenance costs.
Storage systems tend to have high capital costs — like nuclear and wind plants — and so the load factor needs to be high so that the capital repayments can be spread over as many kilowatt-hours as possible. However, load factors of storage systems are modest because systems must spend at least half of the time charging.
Pumped hydro, which accounts for 99% of storage worldwide, has a similar capital cost to wind energy, and so its generation cost will be roughly similar to that of wind, even if it pays nothing for the electricity that is used for the charging purposes. This means a storage system linked exclusively to a wind project roughly doubles the generation cost of the electricity from that wind farm as it has to carry the storage cost as well. It is unlikely to double its value.
There are some locations where storage is already viable, such as in remote areas or on islands. In such places, the alternative to storage for providing power during low wind periods would be diesel generators, possibly using costly imported fuel. Under these circumstances, the cost of electricity from storage may be lower than the cost of generation by diesel.
When the French government issued a call for tenders for its overseas territories early this year it specified developers had to include provision for storage because all locations were on islands or have weak, isolated grids and therefore rely currently on expensive imports of fossil fuels.
"I think storage is economically viable in some markets in some circumstances, says Steven Fawkes, a partner in the corporate finance, energy, renewables and cleantech team at Matrix Group. "It's important that we don't have a generic statement that it's just not economic. Like many technologies, it's very market and application specific."
However, he warns that it can be very hard to develop a sensible business case to attract investors. "The benefits of storage occur in different areas and benefit different parties, so it's quite hard to have a business case that stacks up for grid-scale storage," adds Fawkes. "Also, there are lots of different applications and types of storage, which is confusing for investors."
Another factor that weights in investors' minds is failure, he notes. There have been several high-profile examples of this in recent months, including Beacon Energy, a US firm that was developing a 20MW flywheel energy-storage plant in New York. the company had been given $43 million in federal loan guarantees but filed for bankruptcy in October. It has since been rescued, but stories like this do affect investors' attitudes, Fawkes says.
Gibson acknowledges that high costs remain a significant hurdle for newer technologies, but market interest is growing rapidly as government-funded programmes encourage deployment of a wide range of technologies, she says.
On top of financing difficulties, storage faces regulatory hurdles. Different countries have different regulations for electricity storage. In the US, changes in legislation at federal and state levels are under way to ensure storage is considered as part of the future network.
In Europe, the situation is contradictory. The role of storage has been recognised as an integral part of network operation and as a major component of future smart networks but, at the same time, directives have been written to exclude network operators from the role of generating and supplying electricity.
"Legislation on storage is patchy across the EU, says Price. "It's under investigation and it will change, but don't hold your breath."
Some countries are moving ahead independently. In Germany, energy storage has become a big focus for research and development. In mid-July, 60 energy-storage research projects were launched by the federal ministries for economy, environment and education and research, covering areas that include wind-hydrogen coupling, batteries in distribution networks and heat stores.
The ministries said the initiative aims to support the necessary technological breakthroughs and cost cutting, and contribute to faster market introduction of new energy stores with a view to reaching Germany's target of renewables providing 80% of the electricity supply by 2050.
In Italy, the government has a tender out for battery storage. In July, a consortium of seven European partners led by Italian IT provider Engineering Ingegneria Informatica was formed to build a 39MWh solid-state hydrogen storage facility to balance power supply and demand of renewable energy installed in the Puglia region. The demonstration project has a budget of €23.9 million, €13.8 million of which has been provided by the European Union.
The UK government is revising the commercial and regulatory structure of the country's electricity market but has so far resisted calls to support electricity storage as part of its electricity market reform programme.
Currently, large-scale installations have to pay charges both as a generator of electricity and as a demand customer when charging up. This increases costs disproportionately, says the Institute for Mechanical Engineering. It is calling for storage to be considered in a separate market category from generation, transmission, distribution and supply.
Another hurdle for storage is that it faces competition from demand-side management such as off-peak tariffs, and possibly, in future, from electric cars. Demand-side management can provide short-term operational reserve, and electric cars would enable electricity surpluses from when wind power output exceeds system demand to be used. The Canadian concept of using surplus electricity to generate hydrogen (see case studies) has a similar function.
The advantage of both concepts is that the cost of the car batteries and the gas pipeline is not paid for by the electricity utilities. However, the electrical energy stored in the batteries of electric cars is not generally fed back into the system and sales of electric cars have so far failed to live up to expectations. "All projects on sales of electric vehicles are vastly overinflated and mostly fantasy," says Fawkes.
None of these obstacles is stopping research and development. Over the following pages, Windpower Monthly is reviewing a selection of storage projects around the world. With companies as big as GE and Canada's Enbridge getting in on the act, there is no doubt that ambitions are high, even if those are not matched by the realities of the market.
Fawkes says: "It's a validation of the importance of the market and the scale of the market — for someone like GE it has to be a huge potential market. Storage will be delivered by companies like GE and Siemens because utilities will not trust technology from small developers and that's the nature of it."
CURRENT INNOVATIONS The latest storage technologies in various stages of development
Storage already has a role in providing support services for electricity systems as a whole.
Pumped hydro is particularly useful in delivering substantial amounts of power at short notice to compensate for sudden outages of thermal plants.
Grid operators expect to pay high prices for power under these circumstances, which helps to make this kind of storage viable.
In practice, many pumped storage plants derive their income from a mixture of payments for so-called fast reserve, for charging the store with cheap, surplus power and delivering power at peak times when the price is high.
So far, other technology options are less developed, although some can be used in small systems.
ENERTRAG HYBRID POWER STATION - SARA KNIGHT
Type: Hydrogen and biogas co-generation plant
Enertrag's hybrid power station pilot project in the German state of Brandenburg began way ahead of its time in 2006. The company wanted to demonstrate that a secure and sustainable energy supply based on renewables, in particular wind energy, was possible. The hybrid power station, which uses electricity produced from hydrogen and biogas to compensate for wind's variability, was commissioned in October 2011 and since then Enertrag has been working on optimising operations.
Three Enercon wind turbines, totalling 6.9MW, are the centre pin of the hybrid power station. The electricity they generate can be fed either directly into the 50 Hertz medium-voltage (220kV) transmission network via the Bertikow transformer station or to a 500kW electrolyser, in which hydrogen and oxygen are produced from water.
The hydrogen can be used in three ways: as fuel for road vehicles, as fuel in a 70/30 blend with biogas for co-generation plants producing electricity and heat, or for feeding into the natural gas network.
Enertrag's commitment to using hydrogen is strategic. Wind-generation storage is central to the success of Germany's move away from nuclear energy, and storage technologies that can compensate for seasonal fluctuations in renewable energy production will be needed, comments Enertrag director Werner Diwald. It is estimated that Germany will need 40-60TWh of storage capacity in a system converted to 100% renewables, he explains.
The hybrid power station can be operated in various modes depending on what is required at any time. Hydrogen output can be maximised, electricity can be generated on a steady basis or additional power can be generated in the co-generation plants to balance any error in forecast wind-generation supplies to the transmission network. The controllability of the electricity supply also makes it possible to supply transmission network balancing services or reserve power if other power stations suffer unexpected power outages.
Three months after it went live, Enertrag signed a contract with gas and electricity retailer Greenpeace Energy to supply up to 400MWh of hydrogen in 2012, rising to 1.2GWh in 2013. The required connection to the natural gas network will be finished this year. The hydrogen will comprise a small percentage of the gas in a Greenpeace Energy product named Prowindgas, the rest being natural gas. Roughly EUR0.004/kWh of the gas product price of EUR0.0675/kWh flows to support the construction of wind-power-driven electrolysis plants and mini-cogeneration units.
In April, Enertrag announced deliveries of 400 kilogrammes a month of wind-power-produced hydrogen - equivalent to two days' production a month - to the Total hydrogen filling station on Heidestrasse in Berlin. One kilogramme is sufficient to fuel a car over 100 kilometres. More than 50 fuel-cell cars running on hydrogen are on the roads of Berlin under the Clean Energy Partnership, an initiative set up by 15 companies mainly from the motor and energy sectors to promote hydrogen as a transport fuel. From next year several deliveries per week will be possible to various Total stations in Hamburg and Berlin, says Enertrag.
Investment in the project amounted to more than EUR21 million, with Enertrag providing EUR2 million and oil company Total, energy firm Vattenfall and German railway operator Deutsche Bahn contributing EUR500,000 each. Further funds came from the state of Brandenburg and federal transport ministry support programmes, as well as through company bonds issued by Enertrag.
"Currently, the windgas business case is not positive, but we are convinced that a market for hydrogen as a storage medium will develop in the medium to longer term," says Diwald. A precondition is that the government creates a regulatory framework for the use of windgas for electricity generation, use in vehicles and for heat production, he stresses. "In an optimised overall system with 100% renewables, we anticipate electricity generation costs of about EUR0.12/kWh, with hydrogen as the central energy fuel," he adds.
Diwald believes that hybrid power stations could start to be built in series in the short term, as soon as suitable framework conditions are created. The project has attracted national and international visitors, which shows how much interest there is in the project all around the world,he adds.
ENBRIDGE-HYDROGENICS POWER TO GAS PROJECT - DIANE BAILEY
Type: Hydrogen stored in natural gas pipeline
Two Canadian firms are together investigating using North America's natural-gas pipeline network to store hydrogen produced in an electrolyser.
Calgary-based Enbridge - Canada's second-largest pipeline company and a significant player in renewable-energy with close to 1GW of generating capacity - has taken a C$5 million (US$4.9 million) equity stake in Hydrogenics, a company that designs, builds and installs hydrogen systems.
The electrolyser will produce hydrogen during periods of excess renewable or other surplus generation and inject that hydrogen into Enbridge's pipeline and storage facilities, where it mingles with the natural gas already there.
"For the first time, you have an integration of the very big and complex electricity grid with the very big and complex gas grid," says Chuck Szmurlo, Enbridge's vice-president of alternative and emerging energy. "You have them complement each other and supplement each other, better utilising the resources of both."
The partners want to install a 1MW pilot project in 2013 or 2014 and have identified several potential locations along Enbridge's gas distribution network in Ontario. Szmurlo expects it will carry a price tag in the "single-digit millions" to engineer and build, a cost the partners are hoping to help cover with government grants.
"We have to demonstrate that it actually works the way we believe it will," he says. Once that is accomplished, they foresee stepping up to a 10MW project in 2016 and larger-scale installations in the 100-200MW range sometime after that.
The 1MW and 10MW projects will also test the economics of using hydrogen storage as a tool for managing surplus, says Szmurlo. "Based on some preliminary conversations, we have reason to be optimistic that the system operator would value this enough to render it economically viable," he adds.
A catalyst for moving forward at this point, he says, came from recent technological advances that have made electrolysers bigger, less expensive and more efficient. At typical operating levels, says Hydrogenics CEO Daryl Wilson, the conversion efficiency of electrical energy to hydrogen gas is close to 85-90%.
For pipeline storage to be a feasible option there are some regulatory issues to work out, including deciding just how much hydrogen in the mix is acceptable, not just for pipeline operation, but also for equipment that uses natural gas as fuel. Enbridge has already started discussions with bodies such as the Canadian Gas Association to develop codes and standards "in anticipation of this becoming a bigger idea down the road", says Szmurlo.
The gas pipeline can probably handle about 10% hydrogen without the need for any modifications, he says, although Enbridge believes a 4% limit would be preferable in order to provide an ample margin of safety. But considering that Enbridge's natural-gas storage facilities in Ontario alone have a capacity of 100 billion cubic feet, even that small percentage adds up to significant potential.
"The natural gas grid is so big it would provide gigawatt-hours of storage capacity, more than enough to accommodate the load balancing requirements of independent system operators for the foreseeable future, and orders of magnitude that are better in terms of size and capability than some of the more traditional technologies like pumped hydro, compressed air systems or batteries," says Szmurlo.
The advantage is not just the amount of energy that can be stored, adds Wilson. "It also allows for the transport of energy to where it is needed, when it is needed." That provides for a variety of end uses for the hydrogen-infused natural gas, including as a fuel for electricity generation, transportation and gas appliances such as water heaters and furnaces.
Other storage technologies, including pumped storage and compressed air, not only have geographical limitations when it comes to where facilities can be deployed, Wilson says, but the point of charge and discharge is at the same place.
NORTHERN POWERGRID SMART GRID - CATHERINE EARLY
Two-hour nanophosphate lithium ion batteries
UK network operator Northern Powergrid is working on a three-year project to investigate how using storage technology could reduce peak loading on the network and offset the need for grid reinforcement.
US battery manufacturer A123 Systems is supplying six nanophosphate lithium ion batteries, including a 2.5MVA/5MWh system, two 100kVA/200kWh systems and three 50kVA/100kWh systems. Each will maintain their power capability for up to two hours, which will add flexibility and provide consistent delivery.
"Essentially it's the same technology as batteries that go into computers or electric vehicles - piles of those assembled into units," explains Jon Bird, head of sustainability at Northern Powergrid.
The batteries will be tested on parts of the network that are not stressed so that customers' supply is not put at risk.
Storage is only part of a ú54 million (EUR69 million) wider project, known as Customer-led Network Revolution, which is part-funded through regulator Ofgem's Low Carbon Networks Fund. It will also look at how to shift the time when customers use energy through measures such as off-peak tariffs.
Bird acknowledges that currently batteries are not the cheapest way to deal with supply and demand mismatch, but says the project is looking to a time when battery costs might come down. "The old idea that you just added up customers' demand and ordered enough power stations and a big enough network to deal with all of it is going to be a very expensive option. We need to find smarter ways of bringing the price down."
One of the main aims of the project is to establish whether storage is cost effective. In some cases, new technology might be too expensive, Bird admits. But cost effectiveness often depends on location - it may be more viable to use storage in remote regions on the network than in concentrated urban areas.
"If all we do is put off the time when we need to invest in the network then we'll have saved money in the meantime and that's probably just as important as saving money totally," says Bird.
GE DURATHON - MARK ANDERSON
Type: Sodium battery
Leading US turbine maker General Electric (GE) is taking giant strides towards commercialising its next-generation Durathon sodium battery. In July the company added a $70 million investment on top of the $100 million it announced in April. Near-term plans call for 450 workers at a plant in Schenectady, New York, where annual capacity is expected to reach 1GWh. The current portfolio includes 10, 15 and 20kWh models that aggregate into larger direct-current storage blocks.
The Durathon is based on a chemical exchange between electrically charged sodium and nickel compounds called halides, which require a precise recipe mixed in giant drums resembling cement-truck mixers. The battery operates at temperatures from -20 to +60 degrees Celsius. It occupies half as much space as lead-acid varieties of comparable capacity and recharges up to 3,500 times - ten times more than ordinary batteries, according to GE. It is expected to last up to 20 years with little or no maintenance.
"It's got a lot of possibilities and one of them is as part of wind-development projects," says Brad Roberts, executive director of the Electricity Storage Association, an international trade group. "GE realises there's a market here, and I hope they end up investing a lot more. They're making a big push, which is welcome in the industry - it's a very impressive battery."
GE signed an agreement earlier this year with Arista Power, a New York company that designs a renewable-energy generation and management device called Power on Demand. Coupled with GE's Durathon, the 225kWh system harnesses wind turbines or solar panels to store electricity and release it as alternating current during peak load periods. An electronic box attached to each battery monitors its charge, while computerised status reports are sent to an offsite control room. Larger units are planned.
The system already makes economic sense in places like Boston, southern California and New York City, where peak electricity prices approach $30/kWh, according to Arista CEO Bill Schmitz. "The price in the open market is getting to where it's earning some pretty good paybacks," Schmitz says. "GE's got the one plant up, but they're going to need to get into mass production in multiple places in the world to get the price down."
GE began work on the Schenectady factory at the beginning of 2011 and was producing batteries by the year end. The first major customer, Megatron Federal, a South African engineering company, signed a $60 million purchase agreement totalling 6,000 batteries for delivery next year.
GE has worked to perfect the technology since 2007, when it purchased UK company Beta Research & Development. The business, dubbed GE Energy Storage, is expected to generate more than $1 billion in annual revenue before the decade is out.