Solar Energy and Battery Storage Coupled Provide Demand Response & Utility Peak Shaving

Borrego Solar, a developer, and Stem, an energy storage firm, discuss when PV, storage or both will benefit commercial customers the most.

Sourced through Scoop.it from: www.greentechmedia.com

>” […] Thanks to advancements in technology, there are more energy solutions available to consumers. As a result, the confusion about which option to choose — solar, storage or solar-plus-storage — is growing.

Utility energy costs

To understand the benefits of energy storage and solar at a customer facility, it’s essential to first understand the elements of most organizations’ utility energy costs: energy charges and demand charges. This is the bread and butter for energy managers, but many leaders in finance and/or operations aren’t as aware of the energy cost mix — despite it being one of their largest budgetary line items. It should be noted that this billing structure isn’t in place in every market.

Energy charges, the price paid for the amount of energy used over the course of the billing cycle, are how most people think of paying for electricity. A price is paid for every kilowatt-hour used. Demand charges are additional charges incurred by most commercial customers and are determined by the highest amount of energy, in kilowatts, used at any instant or over some designated timeframe — typically a 15-minute interval — in that billing cycle.

Demand charges are a bit more complex. They come from a need for the grid infrastructure to be large enough to accommodate the highest amount of energy, or demand, needed at any moment in order to avoid a blackout. Every region is different, but demand charges typically make up somewhere between 20 percent and 40 percent of an electricity bill for commercial customers.

Why storage?

Intelligent storage can help organizations specifically tackle their demand charges. By combining predictive software and battery-based storage, these systems know when to deploy energy during usage peaks and offset those costly demand charges. Most storage systems run completely independently from solar, so they can be added to a building whether or not solar is present.

Storage can reduce demand charges by dispensing power during brief periods of high demand, which in essence shaves down the peaks, or spikes, in energy usage. Deploying storage is economical under current market conditions for load profiles that have brief spikes in demand, because a relatively small battery can eliminate the short-lived peaks.

For peak demand periods of longer duration, a larger, and considerably more expensive, battery would be needed, and with the higher material costs, the economics may not be cost-effective. As system costs continue to decline, however, a broader range of load profiles will be able to save with energy storage.

Why solar?

For the commercial, industrial or institutional energy user, solar’s value proposition is pretty simple. For most facilities in states with high energy costs and a net metering regime in place, onsite solar can reduce energy charges and provide a hedge against rising electricity costs. The savings come primarily from producing/buying energy from the solar system, which reduces the amount of energy purchased from the utility, and — when the installation produces more than is used — the credit from selling the excess energy to the grid at retail rates.

The demand savings are a relatively small part of the benefit of solar because the timing of solar production and peak demand need to line up in order to cut down demand charges. Solar production is greatest from 9 a.m. to 3 p.m., but the peak period (when demand for energy across the grid is highest) is typically from 12 p.m. to 6 p.m. If demand-charge rates are determined by the highest peak incurred, customers with solar will still fall into higher demand classes from their energy usage later in the day, when solar has less of an impact.

That being said, solar can reduce a significant portion of demand charges if the customer is located within a utility area where solar grants access to new, solar-friendly rate schedules. These rate schedules typically reduce demand charges and increase energy charges, so the portion of the utility bill that solar can impact is larger.  […]”<

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Japan Installs World’s Largest Offshore Wind Turbine at Fukushima

offshore wind turbine was anchored by the Fukushima Offshore Wind Consortium and is located approximately 12 miles off the cost of Fukushima, a region of Ja

Sourced through Scoop.it from: www.hydrogenfuelnews.com

>” The turbine has been built to withstand 65-foot waves.

The 344-foot 7 MW (megawatt) Offshore Hydraulic Drive Turbine features a rotor diameter of 538 feet and three giant blades, each stretching 262 feet in length. The structure is fastened to the seabed by four 20-ton anchors, and loose chains connect the turbine to the seabed, fortifying it against large waves.

One of the chief engineers of the turbine, Katsunobu Shimizu, told NBC News that “These turbines and anchors are designed to withstand 65-foot waves.” He also explained that “here we can get 32-foot-tall tsunamis. That’s why the chains are deliberately slackened.”

The consortium purposely designed the structures to be able to withstand the fierce and unforgiving weather native to Japan’s waters. In fact, this problematic weather even caused issues during the construction of the turbine. Installations had to be reportedly put on hold on four separate occasions because of typhoons.

The offshore wind turbine is one of three planed for the area.

The Fukushima Offshore Wind Consortium is led by Marubeni Corporation and also involves nine other firms, such as Mitsubishi Heavy Industries, which was the company that supplied the turbine. The $401 million project is funded by Japan’s Ministry of Economy, and was created for the purpose of developing and testing the wind technology for additional commercialization, and to bring new industry to the Fukushima region of Japan that was devastated by the earthquake in 2011.

The 7 MW offshore wind turbine is one of three turbines planned for the facility. When the final turbine is installed later this year, the three turbines are expected to generate a combined total of 14 MW. […]”<

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Virtual Power Plants Aggregate Renewable Energy Battery Storage Systems

Aggregating connected energy storage systems to create ‘virtual power plants’ is likely to become a big part of the next phase of storage, according to the executive director of the US-based Energy Storage Association.

Sourced through Scoop.it from: storage.pv-tech.org

>” […] Part of the beauty is that this kind of storage-based ‘multi-tasking’ could be secondary to the main aims of the storage being installed, such as integrating solar.

“You don’t have to do it every day, but on an infrequent basis you can jump into the marketplace to help make money and subsidise all your projects. And, you can do big things for the grid. You will look like a power plant as far as the grid can tell. You can replace the need for a new peaking plant or something like that. [There are] a lot of great things you can do with distributed storage; the sum of [its] parts is greater than the individual pieces.”

Companies are already trialling the concept in various configurations around the world, analyst Omar Saadeh, senior grid analyst at GTM Research, told PV Tech Storage recently. Saadeh said VPPs are one way utilities could use storage to meet “a higher demand for rapidly deployable grid flexibility”.

One example Saadeh cited was a project called PowerShift Atalantic in Canada, which was “designed to manage and mitigate intermittent power from large-scale wind generation, currently totalling 822MW”.

“Through the multiple flexible curtailment service providers, aggregated loads have the ability to balance wind intermittency by responding to virtual power plant dispatch signals in near-real time, providing the equivalent of a 10-minute spinning reserve ancillary service typically executed by pollution-heavy peaker plants,” Saadeh said.

“Since March 2014, the project included 1,270 customer-connected devices with 18 MW of load flexibility, approximately 90% residential.”

Saadeh said Europe has been especially active on the concept, calling France one of the “leading supporters” of such developments.

“They’ve looked at many promising applications including partial islanding, or microgrids, DER-oriented marketplace development, and renewable balancing services.”

German utility Lichtblick, which claims to generate its power 100% from renewables, is another entity which has already got started on VPPs, which it calls a “swarm” of devices. Its battery system providers in VPP programmes include Tesla Energy and Germany’s Sonnenbatterie. Meanwhile another big Tesla partner, SolarCity, also intends to aggregate storage using the EV maker turned energy industry disruptor’s Powerwall for homes. […]”<

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A New Era for Geothermal Energy in Alberta?

Standard thinking for decades has been that geothermal technology is too costly and inefficient to be a significant source of energy. But a growing number of experts say the time may be right for geothermal to assume a higher profile, especially in ‘perfectly situated’ Alberta.

Sourced through Scoop.it from: www.cbc.ca

>” […] The economics of renewable energy projects are improving as governments begin to introduce carbon taxes and other fees on large carbon-emitting facilities, such as coal power plants.

Geothermal power plants turn hot water into electricity. Companies drill underground for water or steam similar to the process of drilling for oil. The heat is brought to the surface and used to spin turbines. The water is then returned underground.

“I think Alberta is perfectly situated to make the technology work,” said Todd Hirsch, chief economist with ATB Financial. “All the geothermal energy experts say it is all wrong for Alberta. You have to go down so deep to get any heat. Well actually, we have experience drilling through four miles [6.4 km] worth of rock to get at other things that are valuable.”

Hirsch describes geothermal as “a perfectly green, perfectly renewable source of electricity.” He also suggests geothermal could be a boon for the province, where companies have had a knack for developing “marginal resources” such as the oilsands.

“I think geothermal energy might be one that Alberta wants to champion specifically because it doesn’t work here,” said Hirsch. “If we can make it work here in Alberta, then it is a cinch to sell the technology to the Chinese and the Germans and everyone elsewhere geothermal doesn’t work.” […]

What are the costs?

Geothermal power plants cost more money than natural gas facilities. For some perspective, consider the Neal Hot Springs plant in Oregon that was constructed in 2012 for $139 million for 22 megawatts of production.

The Shepard natural gas power plant in Calgary began operating this year with a total cost of $1.4 billion for 800 megawatts of electricity. In this comparison, the geothermal facility costs three times as much per megawatt of power.

Enbridge, a part-owner of the Neal Hot Springs plant, has said the plant saves about 159,000 tonnes per year of carbon dioxide emissions compared to a similar-sized natural gas facility, and about more than 340,000 tonnes per year compared to a coal power plant.

Coal facilities supply nearly 40 per cent of electricity in Alberta.

While the NDP government has yet to announce a specific policy, the party ran on a campaign platform in the recent election pledging to phase out coal.

Premier Rachel Notley has announced an increase to the province’s carbon pricing rules and is expected to announce significant climate change policies this year. Such changes improve the economics of renewable energy projects, such as geothermal.

“It requires a long-term vision to develop,” said Dunn. “How much do we want to invest in the future?” “<

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Geothermal Energy Projects in BC Show Economic Promise

Two potential geothermal energy projects near Pemberton could generate electricity for about seven cents a kilowatt hour — only slightly higher than the 5.8 cents to 6.1 cents a kilowatt hour cost estimate of the Site C dam project.

Sourced through Scoop.it from: www.edmontonjournal.com

>” […]  There are no geothermal energy projects operating in B.C. but the study estimated the cost per kilowatt hour for the nine sites would range from 6.9 to 7.1 cents for Pebble Creek and Meager Creek near Pemberton to 17.6 cents for Clarke Lake near Fort Nelson.

BC Hydro senior strategic technology specialist Alex Tu said some of the projects appear promising but stressed the cost estimates are still “very uncertain” and carry a lot of risk.

“Even though it says seven cents a kilowatt hour, it’s still a risky proposition,” he said. “All the geothermal in the province is still looked at as very uncertain and very high risk but if you can make the project happen, seven cents is a good price.”

Tu noted BC Hydro invested tens of millions of dollars drilling at the two Pemberton area sites in the 1970s and 1980s but could only produce enough steam for a 20-kilowatt demonstration facility that operated for 18 months.

Geothermal power facilities work by drilling into the earth and redirecting steam or hot water into turbines that convert the energy from the fluid into electricity.

Tu said Hydro has always been open to geothermal power as an alternative energy source but no geothermal projects have ever been submitted to Hydro in any of its calls for power from independent power producers.

Hydro’s standing offer program offers to pay producers $100 a megawatt hour for smaller energy projects of up to 15 megawatts. The two Pemberton area geothermal sites each have estimated capacities of 50 to 100 megawatts.

Borealis GeoPower chief geologist Craig Dunn, whose Calgary-based firm hopes to build two geothermal power plants in B.C. by 2018, said he was excited by the Kerr Wood study, which was commissioned by BC Hydro and Geoscience BC.

“I think it’s a giant step forward in recognizing that geothermal is a viable energy opportunity for the province of British Columbia,” he said.

Dunn said the drilling and turbine technology associated with geothermal power continues to improve, making that form of energy more economically viable than ever.

“As a private developer, I know that my costs are significantly less than the estimates,” he said.

Tu estimated the cost of the two proposed Borealis geothermal sites near Valemount and Terrace at about $120 to $140 a megawatt hour but Dunn said current drilling economics — with many drilling rigs now inactive due to the oil industry slowdown — could cut that estimate by 25 to 50 per cent.  […]”<

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Economist reports proposed Site C Dam ‘dramatically’ more costly than BC gov’t claims

Peace Valley Landowners Association commissioned leading U.S. energy economist, Robert McCullough, to look at the business case for what will be province’s most expensive public infrastructure project

Image source:  http://unistotencamp.com/?p=601

Source: www.theglobeandmail.com

>”Just weeks before BC Hydro plans to begin construction of the $8.8-billion Site C project, a new report says the Crown corporation has dramatically understated the cost of producing power from the hydroelectric dam.

…Mr. McCullough, in his report, said it appears the Crown corporation BC Hydro had its thumbs on the scale to make its mega project look better than the private-sector alternatives.

“Using industry standard assumptions, Site C is more than three times as costly as the least expensive option,” Mr. McCullough concluded. “While the cost and choice of options deserve further analysis, the simple conclusion is that Site C is more expensive – dramatically so – than the renewable [and] natural gas portfolios elsewhere in the U.S. and Canada.”

The report challenges a number of assumptions that led the government to conclude that Site C is the cheapest option. Mr. McCullough noted that the province adopted accounting changes last fall that reduced the cost of power generated by Site C. He said those changes are illusory and the costs will eventually have to be paid either by Hydro ratepayers, or provincial taxpayers.

Mr. McCullough, a leading expert on power utilities in the Pacific Northwest, also disputes the rate that BC Hydro used to compare the long-term borrowing cost of capital for Site C against other projects, noting that other major utilities in North America use higher rates for such projects because they are considered risky investments. The so-called discount rate is critical to the overall cost projections, and he said the paper trail on how the Crown arrived at its figure “can only be described as sketchy and inadequate.”

The report, obtained by The Globe and Mail, will be released on Tuesday by the PVLA.

The group will call on Premier Christy Clark to delay construction to allow time for a review by Auditor-General Carol Bellringer.

Ken Boon, president of the association, said the government needs to put the project on hold because it has approved the project based on poor advice. […]”<

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Water Prices in 2015 Up 6 Percent in 30 Major U.S. Cities

Continuing a trend that reflects the disrepair and shows no sign of slowing, the price of residential water service in 30 major U.S. cities rose faster than the cost of nearly every other household staple last year …

Source: www.circleofblue.org

>” […] The economics of water — particularly the cost of treatment, pumping, and new infrastructure, as well as the retail price for consumers — gained renewed prominence as California and Texas, America’s two most populous states, face historic droughts and water managers seek to rein in water consumption, with price increases as one tool in their arsenal.

The average monthly cost of water for a family of four using 100 gallons per person per day climbed 6 percent, according to data collected from the utilities. It is the smallest year-to-year change in the six-year history of the Circle of Blue survey but comparable to past years. The median increase this year was 4.5 percent. In comparison, the Consumer Price Index rose just 1.8 percent in the 12 months ending in March, not including the volatile food and energy sectors. Including food and energy, prices fell by 0.1 percent.

For families using 150 gallons and 50 gallons per person per day, average water prices rose 6 percent and 5.2 percent, respectively.

The survey results reflect broad trends in the municipal water industry that nearly every U.S. utility must grapple with, according to Andrew Ward, a director of U.S. public finance for Fitch Ratings, a credit agency.

Distribution pipes, which can branch for thousands of miles beneath a single city, have aged beyond their shelf life and crack open daily. Some assessments peg the national cost of repairing and replacing old pipes at more than $US 1 trillion over the next two decades. In addition, new treatment technologies are needed to meet Safe Drinking Water Act and Clean Water Act requirements, and cities must continue to pay down existing debts. At the same time, conservation measures have proven successful. Utilities are selling less water, but they still need big chunks of revenue to cover the substantial cost of building and maintaining a water system. All together, these and other factors amount to a persistent upward pressure on water rates. […]

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DOE Invests in Super-Critical Carbon Dioxide Turbine Research to Replace Steam for Electric Power Generators

The U.S. Department of Energy hopes to create a more efficient turbine that uses CO2 to make electricity

Source: www.scientificamerican.com

“> […]

Whether burning coal, concentrating sunlight or splitting atoms, most thermal power plants use the energy for the same thing: heating water into steam to drive a turbine. Steam-based generation produces 80 percent of the world’s electricity.

After more than a century of incremental improvements in the steam cycle, engineers have plucked most of the low-hanging fruit and are chasing diminishing returns, spending millions of dollars for every percentage point of efficiency improvement. These upgrades propagate to other steps in electricity production, allowing power plants to extract more work for a given unit of fuel.

In a fossil fuel-fired generator, this means less carbon dioxide emissions for the same unit of electricity produced. For a solar thermal plant, this results in higher capacity at lower operating costs.

Now engineers are looking into replacing steam with supercritical carbon dioxide, a technique that could unlock up to 50 percent greater thermal efficiency using a smaller, cheaper turbine.

Last month, in a budget briefing and in two different hearings before Congress, Energy Secretary Ernest Moniz specifically mentioned the Department of Energy’s supercritical carbon dioxide initiatives. The department’s 2016 budget request allocates $44 million for research and development on this front, including a 10-megawatt supercritical turbine demonstration system.

A simpler, smaller, cleaner machine
The term “supercritical” describes the state of carbon dioxide above its critical temperature and pressure, 31 degrees Celsius and 73 atmospheres. Under these conditions, carbon dioxide has a density similar to its liquid state and fills containers the way it would as a gas.

Coffee producers are already using supercritical carbon dioxide to extract caffeine from beans. Materials companies are also using it to make plastics and ceramics.

“From a thermodynamic perspective, it’s a very good process fluid,” said Klaus Brun, machinery director at the Southwest Research Institute, a nonprofit research and development group. “You get a fairly efficient cycle and a reasonable firing temperature.”

In its supercritical state, carbon dioxide is nearly twice as dense as steam, resulting in a very high power density. Supercritical carbon dioxide is easier to compress than steam and allows a generator to extract power from a turbine at higher temperatures.

The net result is a simpler turbine that can be 10 times smaller than its steam equivalent. A steam turbine usually has between 10 and 15 rotor stages. A supercritical turbine equivalent would have four.

“We’re looking at a turbine rotor shaft with four stages on it that’s 4 inches in diameter, 4 feet long and could power 1,000 homes,” said Richard Dennis, turbine technology manager at the National Energy Technology Laboratory.

He noted that the idea of a supercritical carbon dioxide power cycle dates back to the 1940s, but steam cycles were already very efficient, well-understood and cheap, creating an uphill slog for a new power block to catch on. In addition, engineers were still finding ways to improve the combustion side of power production, so the need to improve the generation side of the plant wasn’t as acute until recently. […]”<

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Closed Loop Cooling Saves Millions of Gallons of Water in Texas Combined Cycle Natural Gas Power Plant

Source: gereports.ca

>” […] Instead of water, each of the two plants will use two powerful air-cooled “Harriet” gas turbines and one air-cooled steam turbine developed by GE. “The technology uses the same cooling principle as the radiator in your car,” Harris says. “You blow in the air and it cools the medium flowing in closed loops around the turbines.”

The power plants, which are expected to open next year, will be using a so-called combined cycle design (see image below) and produce power in two steps. First, the two gas turbines (in the center with exhaust stacks) extract energy from burning natural gas and use it to spin electricity generators. But they also produce waste heat.

The system sends the waste heat to a boiler filled with water, which produces steam that drives a steam turbine to extract more energy and generate more power.

But that’s easier said than done. The steam inside the steamturbine moves in a closed loop and needs to be cooled down back to water so it could be heated up again in the boiler. “Normally, we cool this steam with water, which evaporates and cools down in huge mechanical cooling towers,” says GE engineer Thomas Dreisbach. “A lot of the cooling water escapes in those huge white clouds you sometimes see rising from towers next to power plants.” The Exelon design is using a row of powerful fans and air condensers (rear right) to do the trick and save water.

Similar to the steam turbines, GE’s Harriet gas turbines also use air to chill a closed loop filled with the coolant glycol and reduce the temperature inside the turbine. The combined efficiency of the plant will approach 61 percent, which in the power-generation industry is like running a sub 4-minute mile. […]”<

 

 

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China’s Switch to LNG From Coal Will Cut Global Pollution

To many people, natural gas seems to be more of the same, a continuation of the old fossil fuel path that has driven industrialization, air pollution and global warming.

Source: www.vancouversun.com

“> […]  China is currently producing twice the greenhouse gases of the United States. And its emissions are growing rapidly. Its emissions surpassed those of the U.S. in 2006, reached double the U.S. in 2014, and are expected to rise by seven per cent per year for the foreseeable future. China obtains 70 per cent of its electricity from burning coal, by far the worst polluter. China has plans for doubling its use of coal in the next 10 to 15 years. Meanwhile, the emissions from the U.S. have stabilized, partly from a slowing economy, but the biggest effect came from a switch from coal to natural gas. If you replace an old coal power plant with a modern natural gas one, you can cut carbon dioxide emissions by a factor of three.

Natural gas doesn’t cut emissions to zero; it is still a fossil fuel. But it obtains much of its energy from hydrogen, an atom that out numbers the carbon atoms in methane (the key component of natural gas) by 4:1. Natural gas can be burned with much higher efficiency than coal, by use of a combined cycle turbine that harnesses both gas and steam power generation.

China wants to move away from coal, to natural gas, nuclear, and solar. Their chief concern is not global warming, but the horrific air pollution that is killing an estimated 4,000 people per day in China, 1.6 million per year. […]”<

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