Siemens is to team up with three US energy labs to test new technologies to bolster electricity supply, options and resiliency.

Siemens Corporate Technology, the company’s central research and development unit located in Princeton, New Jersey, has signed a memorandum of understanding with three US Department of Energy R&D facilities: The National Renewable Energy Laboratory in Golden, Colorado; the Oak Ridge National Laboratory in Oak Ridge, Tennessee; and the Pacific Northwest National Laboratory in Richland, Washington.

The memorandum established the framework for research scientists to share information and resources. They could collaborate on technologies to help integrate innovative power electronic devices with the electric grid, including smart inverters for solar panels, batteries, and electrical vehicles that are capable of supporting the nation’s power system.

The MOU may also lead to jointly-led scientific workshops, lectures, and symposia, as well as co-written publications and journal articles.

The potential collaboration is expected to leverage Siemens experience commercializing innovative power system technologies by supplying its Software Defined Inverter (SDI) technology, which would be tested and validated at specialized grid facilities at the three national laboratories. This promising new technology, once validated, could be incorporated into new technologies to strengthen and modernize the nation’s electric grid, including microgrids and distributed energy resources such as energy storage.

“Siemens is committed to developing innovative technologies needed to ensure that the power grid of the future is more resilient, secure, and capable of supporting distributed and low-carbon power generation assets,” said Ulrich Muenz, Siemens Corporate Technology research group head. “Collaborating with the Department of Energy’s U.S. National Laboratories and co-creating with the nation’s energy community is crucial to modernizing and enhancing America’s energy infrastructure.”

The MOU covers a five-year period with provisions to renew or extend it.

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Thousands of megawatt-hours of electrical energy squirreled away into utility-scale energy-storage plants to cover the spread between generated renewable energy and the lowest reliable operating limit (LROL) during the 10 a.m. to 3 p.m. “duck curve” period of the day — does this sound like a glimpse into the far future of major utilities across the United States and the world? But the future has already arrived at the Carolina operating companies of Duke Energy.

For example, the Duke Energy Progress (DEP) Company, serving customers primarily in the eastern half of North and South Carolina, managed a whopping 106 GWh of excess energy in 2017, largely generated from the vast fleet of mostly utility-scale solar-energy resources in North Carolina. “Excess energy” is generated whenever the net demand load falls below the LROL. This tends to happen during the period of the day of greatest solar energy generation, between 10 a.m. and 3 p.m., as shown in Figure 1.

A Balancing Authority (BA) is responsible for achieving continuous balance between available energy and demand for energy in real time and therefore, needs to commit generation units that can reliably meet peak demands, expected net-demand ramp rates and reserve requirements to regulate frequency and support contingency conditions.

The LROL is the minimum MW level needed to keep the required generating units online. In addition, the utility is bound by private power agreements with guaranteed “take” provisions. Between the “take” provisions and the reliability requirements enforced by NERC, the problem is two-fold: (1) maintaining sufficient local regulating reserves to manage intermittency and net-demand ramping, and (2) managing excess energy, which is not a simple matter of switching open a recloser at a large solar-generating facility or shutting down a gas-fired turbine.

All of that renewable energy has got to go somewhere. According to Kat Sico, transmission operations engineer for DEP, “When resources are available, excess energy can be managed by reducing internal generators or exporting the excess energy via the joint dispatch dynamic schedule. This energy either serves Duke Energy Carolina’s (DEC’s) retail load or utilizes DEC’s 2100 MW of pumped storage load capabilities.”

This dynamic schedule has been implemented under the Joint Dispatch Agreement (JDA), in which DEP and DEC are permitted to share “non-firm” energy in order to meet their customers’ energy demand in an economic manner. Since solar generation has guaranteed “take” provisions for DEP, the excess energy that is transferred from DEP to DEC comes from other generation resources. DEC primarily serves the western parts of North and South Carolina, a region encompassing the Appalachian mountain range, where DEC’s pumped-hydro operations are in motion.

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A 6MW / 6MWh containerised energy storage system will help provide power to all 19,000 inhabitants of a tiny Caribbean island, installed by Wärtsilä and its recently-acquired energy storage system integrator subsidiary Greensmith.

The project is being executed on the island of Bonaire, a Dutch Antilles territory off the coast of Venezuela. Local power generation company ContourGlobal Bonaire, itself a subsidiary of London-based power generator ContourGlobal, contracted Wärtsilä to carry out the work after several apparently successful years of the two parent companies working together in various market segments in other regions of the world.

Expected for completion in April this year, the project will pair the new advanced battery energy storage system with the island’s generation and distributed energy resources. A Wärtsilä-Greensmith representative told Energy-Storage.news that this will include, but not be limited to, existing equipment.

These are: 11MW of wind generation, 14MW of diesel engines, 3MW of backup thermal generation and an existing 3MW battery system. The latter is only used to provide backup in the event of outages and other issues. Wärtsilä-Greensmith has been handed an EPC (engineering, procurement and construction) contract that includes hardware (batteries, inverters) as well as energy management software.

The representative said that the project will increase the island’s ability to use renewable energy even without new investment in generation as some of the output of existing assets requires curtailment at present and that surplus is not being used. The project will also aid the reliability and security of supply of energy to the island.

“This is the important first step in enabling Bonaire to significantly increase renewable penetration and positions the grid to integrate solar as the Island of Bonaire looks to develop,” the representative said.

Greensmith CEO John Jung – and others – have repeatedly talked up the growing importance of software, not only in controlling and managing standalone energy storage projects but also in coordinating complete microgrid systems and distributed and smart grids. The Bonaire project will utilise GEMS, Greensmith Energy’s proprietary software platform, for control and dispatch.

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Traditionally, utilities built and operated a portfolio of generation plants consisting of a few large base load units – typically nuclear or coal – some intermediate plants and a number of peakers – typically natural gas fired units with rapid ramping capability (visual below).

Base load units ran flat out year-round, 24/7; the intermediate units were used to fill the fluctuations in demand while the peakers were used sparingly to meet occasional surges in demand, say on hot summer afternoons when air conditioning load would spike for a few hours.

Fast forward to 2019 and beyond and one is likely to encounter a different paradigm where on many networks an increasing share of generation is provided by renewable resources, most likely wind and solar, neither of which is dispatchable nor totally predictable.

In this environment, what the grid operators crave the most is flexible generation, especially those with rapid ramping capability to fill in any unexpected shortfalls in renewable generation and to maintain the system’s reliability.

This much is old news. What is new is that recent advances in energy storage technology, especially batteries, coupled with dramatic cost declines is making storage increasingly attractive relative to gas- fired peaking plants, which are not particularly efficient, are highly polluting and are expensive to maintain. Moreover, since peakers are infrequently used and only for a limited number of hours, they tend to be poor investments, sitting idle most of the time.

A case in point was a decision by San Francisco-based Pacific Gas & Electric Company (PG&E) backed by the regulator, the California Public Utilities Commission (CPUC) in Nov 2018 to replace 3 gas peakers with large battery storage units that would be among the world’s largest when completed.

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Australia is expected to be the world’s largest residential energy storage market in 2019, according to a short note published this week by Bloomberg New Energy Finance, accounting for 30% of global demand as household storage demand triples.

Bloomberg New Energy Finance (BNEF) published one of its Shorts on Tuesday highlighting the major headline from its latest report, Australia Residential Storage to Triple, Despite High Cost. According to Bloomberg, state governments across Australia are getting behind residential storage which, in turn, is solidifying Australia as one of the most attractive markets on the globe.

More than just installing capacity, the increasing demand is convincing industry leaders to invest in setting up assembly factories. Unsurprisingly — given its recent headline status as home to a mammoth Tesla battery — South Australia has already attracted Sonnen GmbH, AlphaESS, and Eguana Technologies to set up local assembly facilities.

Bloomberg New Energy Finance expects over 70,000 households across Australia will install batteries this year — helped in large part by the provision of AU$147 million in State government subsidies as well as low-interest loans and demand response schemes, all serving to incentivise and inspire interest.

Incentivizing the energy storage still further is the possibility of an election win by the Federal opposition — with an election due for no later than May 18, 2019, and a Labor Party win shaping up to be more than likely — which will see them commit a further AU$200 million in subsidies for another 100,000 household batteries from 2020.

BNEF expects that the eventual path could be somewhat bumpy, but will likely nevertheless be an attractive market even after policy support ends, thanks to one of the world’s highest penetration of household solar which currently already sits at one in five houses partnered with high electricity costs which are pushing customers to search for alternatives.

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Decarbonizing the world’s electricity grids won’t be an easy task, but it is a necessary one if we’re going to mitigate some of the worst effects of climate change. Since wind and solar power are intermittent, part of decarbonizing the grid will involve storing renewable energy for use when the Sun isn’t shining and the wind isn’t blowing.

While day-to-day storage will cover the gaps when the wind slacks or the Sun sets, on grids with more than 80 percent renewable energy you’re also going to want inter-seasonal storage. This is because sun and wind are seasonal, and energy demand is also seasonal—people use a lot more energy in the winter than they do in the spring, because it’s darker and colder outside.

Researchers from the University of Edinburgh and the University of Strathclyde think that one potential step toward seasonal storage should involve identifying large underground saline aquifers where energy could be stored as compressed air. Saline aquifers are usually found underwater; the compressed air will displace some of the water, which can be discarded, as it’s not potable.

Massive reservoirs of compressed air could handle the inter-seasonal gaps that high-renewable grids might struggle with. The researchers suggest a system where excess renewable energy is used to compress air and pump it down into a saline aquifer over the course of several months. Then, when it’s needed in the winter, the air is brought back up and expanded, powering a turbine that drives electricity back onto the grid.

The cycle is comparable to how many regions store and use natural gas. That is, excess natural gas is pumped into underground storage caverns where it sits for a few months. In the winter, when gas is needed to heat homes, those stores are drawn down. The difference here is that the energy being stored isn’t chemical.

The researchers used existing geological mapping that was conducted around the United Kingdom to find potential storage areas for carbon dioxide (CO2), but their method for vetting geological repositories for compressed air storage could be applied to underwater geographies around the world.

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New York — The New York Independent System Operator’s five-year power grid plan sets out six strategic initiatives to guide its projects and resource allocation that include pricing carbon emissions into the wholesale market, which could increase power prices by about $10-$15/MWh, an analyst said Wednesday.

“Our updated Strategic Plan is a living document that embraces the challenges and opportunities of the grid’s ongoing transformation,” NYISO interim President and CEO Robert Fernandez said in a statement Tuesday.
“The plan reflects the NYISO’s essential role in harmonizing public policy with technological innovation in a manner that delivers economically efficient and reliable energy to consumers,” Fernandez said.

Integrating public policy into NYISO-administered wholesale markets often refers to the grid operator’s ongoing carbon pricing efforts, an initiative that could go into effect in the second quarter of 2021, NYISO has said.

“The carbon prices being discussed for implementation in New York are significantly higher than the current [Regional Greenhouse Gas Initiative] RGGI prices,” Manan Ahuja, senior director of North America power modeling at S&P Global Platts Analytics, said in an email Wednesday.

If implemented, the carbon prices could add significantly to the wholesale power prices, increasing location-based marginal prices “by about $10-$15/MWh (in the proposed carbon price vs the RGGI price) based on our recent modeling,” Ahuja said.

Such changes would also impact decisions about what type of supply resources get built or retire, he added.

The strategic plan is based on the NYISO board of directors’ review of financial and regulatory outlooks, as well as the economic and environmental factors affecting market participants and stakeholders, the grid operator said in a statement Tuesday.

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Now in its fourth year, the Energy Storage Summit has been supporting the deployment of this world-changing set of technologies in the UK and beyond since it began and it returns in just a few weeks’ time for the 2019 edition.

The 2018 event saw the industry come together in London and our editorial team was able to report a huge amount of exclusive news and commentary that emerged. That’ll happen again this year, but if you really want to hear the latest insights first-hand and meet many of the names and faces behind the stories and projects that make the news, the only way to do that will be by attending the show.

It takes place on 26 and 27 February 2019, once again at Victoria Park Plaza in the centre of England’s capital. We expect a similar number of attendees to last year, when more than 350 delegates were welcomed over two days.

It’s fair to say the scope of the event is changing each year, as the market itself changes. The Energy Storage Summit programme is designed to both respond to the market’s dynamics as well as itself helping set the agenda with forward-thinking technology sessions and case studies.

There’s been a growth in importance of behind-the-meter energy storage, not just in the UK but in many parts of the developed world. That is to say, there’s been widespread recognition that there’s a lot more potential in energy storage systems deployed to benefit individual households or businesses than we often recognise. Companies working to deploy and connect these systems, or to aggregate them together to unleash their full capabilities such as Kiwi Power and Pivot Power will be on-hand to talk about these topics.

There’s also been a wave of finance activity – although in all honesty there remains a lot of work to be done to get the finance community on-board and au fait with energy storage. Again, the likes of Wermuth Asset Management, Ingenious Capital and First Imagine will be representing that community. There’s no doubt there’ll be a lively two-way flow of information and views with the energy storage industry there.

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A local authority in England has unveiled two landmark solar-plus-storage projects on existing landfill sites which aim to be the first of their kind in the UK.

Cambridgeshire County Council (CCC), which has been a prominent proponent of renewables, last week unveiled plans to develop the energy projects on landfill sites in Woodston and Stanground, both near Peterborough.

The Stanground site is proposed to be the largest, combining a 2.25MW ground-mount solar array with a 10MW battery storage system, while the Woodston project will use a 3MW battery. Both battery systems are expected to have a 2C charge-discharge rate.

Minutes from a CCC committee meeting dated to 14 September 2018 said that, with demand response and balancing capacity services sold to National Grid expected to form the bulk of those revenues, Stanground could raise £1.4 million (US$1.82 million) in its first year of operation and Woodston £380,000. The council noted that “grid services are an evolving market with uncertain revenue streams”.

“However, market reports confirm that with a growing proportion of renewable energy on the grid, the necessity for a response to balance periods of high demand or high penetration of renewables is increasing,” the document continues, adding that there is a “high degree of confidence” that the need for grid services will grow in the longer term.

Crucially, revenue generated from the services is to be used to help fund the county council’s frontline services, with previously-stated revenue generation estimates placing the sites’ combined contribution at almost £46 million over 25 years.

CCC’s energy investment team has worked with frequent partner Bouygues E & S for the sites’ design.

CCC’s experience with solar has been long standing and the council remains one of the most vocal supporters of the technology. In late 2016 CCC confirmed the completion of the 10MW, council-owned Triangle Solar Farm in Soham, the second utility-scale solar project to be completed under the Contracts for Difference mechanism.

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For decades, the North Sea has been delivering much of the oil and gas to the world’s global supply of fossil fuels.

As technologies advanced and climate change concerns increased, the North Sea also became a leader in offshore wind capacity installation and innovation.

For the countries on the North Sea, and for all renewable projects around the world for that matter, the key challenge in boosting the share of renewables in the power mix is a way to find a reliable cost-efficient way to store the energy produced so it can be released when needed.

A new study by a team of scientists from the University of Edinburgh suggests that porous rocks on the North Sea bed could act as energy storage facilities.

Julien Mouli-Castillo of the University of Edinburgh’s School of GeoSciences and his team suggest in an article in Nature Energy that the so-called compressed-air energy storage (CAES) technology could be applied in those porous rocks to store energy for a few months, for example to have it readily available during peak electricity winter demand in the UK.

CAES could use electricity from renewables to power a motor that generates compressed air. This compressed air would then be stored at high pressure in the porous rock, through a deep well drilled into the rock. When electricity demand is high, the compressed air would be released from the well and power a turbine to generate electricity to send to the power grid.

The scientists suggest that the CAES approach could be used in porous rocks where seismic exploration data for oil and gas is available, if those rocks are close to renewable energy sources. The UK meets those two criteria—the UK North Sea is well explored. The North Sea and the nearby Atlantic Ocean are also home to 90 percent of global installed offshore wind capacity, according to the International Renewable Energy Agency (IRENA).

Mouli-Castillo and team have designed a modeling approach to predict the potential of North Sea porous rocks to store energy.

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