A recycled paper mill claimed to be the most advanced in Europe has been officially opened by Michael Fallon, the UK's minister of state for business & energy, at Partington Wharfside, Trafford.
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The future for the metal aluminum has never looked better, for the great investment it represents as a multi-faceted energy efficiency lending material, electrical energy storage medium (battery), and for the advancement of renewable energy sources. These are spectacular claims, and yet in 1855 aluminum was so scarce it sold for about 1200 $/Kg (1) until metallurgists Hall…
Author: Duane M. Tilden, P.Eng (January 14th, 2016) Abstract: Energy sources and pricing are hot topics world-wide with the Climate Change agenda leading the way. Last year at the 2015 Paris Climate Conference long-term goal of emissions neutrality was established to be by as soon as 2050. Alberta currently produces more atmospheric carbon emissions and other pollutants…
Originally published on Solar Love. A new study has concluded that utility-scale solar PV systems across the US are “significantly” more cost effective than rooftop solar PV systems. Sp…
Duane Tilden's insight:
"[...] the study, conducted by economists at global consulting firm The Brattle Group, found that utility-scale solar PV systems were more cost effective at achieving the economic and policy benefits of PV solar than rooftop or residential-scale solar was.
The study, Comparative Generation Costs of Utility-Scale and Residential-Scale PV in Xcel Energy Colorado’s Service Area, published Monday, is the first of its kind to study a “solar on solar” comparison.
“Over the last decade, solar energy costs for both rooftop and bulk-power applications have come down dramatically,” said Dr. Peter Fox-Penner, Brattle principal and co-author of the study. “But utility-scale solar will remain substantially less expensive per kWh generated than rooftop PV. In addition, utility-scale PV allows everyone access to solar power. From the standpoint of cost, equity, and environmental benefits, large-scale solar is a crucial resource.”
The study yielded two key findings:The generation cost of energy from 300 MW of utility-scale PV solar is roughly ½ the cost per kWh of the output from an equivalent 300 MW of 5kW residential-scale systems when deployed on the Xcel Energy Colorado system, and utility-scale solar remains more cost effective in all scenarios considered in the study.In that same setting, 300 MW of PV solar deployed in a utility-scale configuration also avoids approximately 50% more carbon emissions than an equivalent amount of residential-scale PV solar.
The report itself was commissioned by American thin-film photovoltaic manufacturer and utility scale developer First Solar with support from Edison Electric Institute, while Xcel Energy Colorado provided data and technical support. Specifically, the report examined the comparative customer-paid costs of generating power from equal amounts of utility-scale and residential/rooftop-scale solar PV panels in the Xcel Energy Colorado system.
A reference case and five separate scenarios with varying degrees of investment tax credit, PV cost, inflation, and financing parameters were used to yield the report’s results.
The specifics of the study’s findings, which imagined a 2019 Xcel Energy Colorado system, are as follows:utility-scale PV power costs ranged from $66/MWh to $117/MWh (6.6¢/kWh to 11.7¢/kWh) across the five scenariosresidential-scale PV power costs were well up, ranging from $123/MWh to $193/MWh (12.3¢/kWh to 19.3¢/kWh) for a typical residential-scale system owned by the customerthe costs for leased residential-scale systems were even larger and between $140/MWh and $237/MWh (14.0¢/kWh to 23.7¢/kWh)the generation cost difference between the utility- and residential-scale systems owned by the customer ranged from 6.7¢/kWh to 9.2¢/kWh solar across the scenarios
The authors of the report put these figures into perspective, including the national average for retail all-in residential electric rates in 2014, which were 12.5¢/kWh. [...]"
Duane Tilden's insight:
"[...] "Fracking", or Hydraulic Fracturing, is a new technology that has opened up immense resources of natural gas buried in deep shale beds. The process involves injection of highly-pressurized water, sand and chemicals to shatter underground layers of shale and extract previously inaccessible natural gas.
Tranquillity Irrigation District, which serves the water needs of the 10,750-acre agricultural community of Tranquillity in Fresno County, today announces plans to build a 1.8 megawatt ground-mounted solar tracker system that will provide enough electricity to meet 50 percent of the agency’s energy demand. Borrego Solar Systems Inc., a leading designer, developer, installer and O&M …
Duane Tilden's insight:
"[...] Tranquillity will save a net $10 million over the 25-year term of its power purchase agreement (PPA)—a financing mechanism that enables customers to invest in solar without any upfront costs. The District will buy the energy produced from the system owner at a set price over the PPA agreement term.
“Solar was clearly the best use for our site, especially considering the savings we’ll realize for our residents through the PPA – it’s truly a win-win,” said Danny Wade, general manager of Tranquillity Irrigation District. “The reality is that we will continue to be plagued with limited water resources for the foreseeable future, and solar is a sustainable solution to help us deal with the resulting energy demand and cost increase due to the drought. Any water district in the state should be investigating whether solar works for them.”
Given the ongoing drought in California, the District has needed to use its wells more than it had pre-drought. As a result, more electricity is needed to power the pumps bringing water toward the surface. The District is trying to provide water to its landowners and the community of Tranquillity as efficiently and economically as it can. For example, the District recently received a $5 million grant from the California State Department of Health to build a necessary water treatment facility. The solar tracker system will be placed adjacent to the treatment facility on land already owned by the District. [...]
In its first year of operation, the array will generate an estimated 3.3 million kilowatt-hours of electricity— enough to power approximately 450 homes. The installation will offset more than 760 metric tons of CO2 equivalents annually, which is the equivalent of taking 162 cars off the road for a year or the amount of carbon sequestered by 630 acres of mature U.S. forests each year.ABOUT TRANQUILLITY IRRIGATION DISTRICT
Tranquillity Irrigation District was formed January 22, 1918, as a public agency designed to serve the local community with water supplies. It is the second oldest such agency in Fresno County. A Board of Directors elected from the community at-large governs the District. The District is approximately 10,750 acres in size and is located in the west central portion of Fresno County in the Great Central Valley of California. The District farmland produces a variety of commodities including: cotton (pima and acala), canning tomatoes, alfalfa for seed, sugar beets and almonds. Its principal community is the unincorporated town of Tranquillity. [...]"
Borrego Solar, a developer, and Stem, an energy storage firm, discuss when PV, storage or both will benefit commercial customers the most.
Duane Tilden's insight:
>" [...] 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. [...]"<
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.
Duane Tilden's insight:
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. [...]"<
The team took off-the-shelf geothermal generators and hooked them to pipes carrying boiling waste water. They’re set to flip the switch any day. When they do, large pumps will drive the steaming water through the generators housed in 40-foot (12-meter) containers, producing electricity that could either be used on site or hooked up to power lines and sold to the electricity grid.
Duane Tilden's insight:
>"Oil fracking companies seeking to improve their image and pull in a little extra cash are turning their waste water into clean geothermal power.
For every barrel of oil produced from a well, there’s another seven of water, much of it boiling hot. Instead of letting it go to waste, some companies are planning to harness that heat to make electricity they can sell to the grid.
Companies such as Continental Resources Inc. and Hungary’s MOL Group are getting ready to test systems that pump scalding-hot water through equipment that uses the heat to turn electricity-generating turbines before forcing it back underground to coax out more crude.
Though the technology has yet to be applied broadly, early results are promising. And if widely adopted, the environmental and financial benefits could be significant. Drillers in the U.S. process 25 billion gallons (95 billion liters) of water annually, enough to generate as much electricity as three coal-fired plants running around the clock -- without carbon emissions.
“We can have distributed power throughout the oil patch,” said Will Gosnold, a researcher at the University of North Dakota who’s leading Continental Resources’ project well.
Geothermal power also holds out the promise of boosting frackers’ green credentials after years of criticism for being the industry’s worst polluters, says Lorne Stockman, research director at Oil Change International, an environmental organization that promotes non-fossil fuel energy.
“This is one way to make it look like the industry cares about the carbon issue,” he said. Even if steam generates less carbon than other oil field power sources, “if you’re in the business of oil and gas, you’re not part of the solution.”Cheap Oil
Then there’s the money. With crude at less than $50 a barrel, every little bit can help lower costs. At projects like the one being tested by Continental Resources in North Dakota, a 250 kilowatt geothermal generator has the potential to contribute an extra $100,000 annually per well, according to estimates from the U.S. Energy Department.
That’s not big money and the $3.4 million cost to test the technology is still too much to apply to each of Continental’s hundreds of wells. Yet if the company can lower the costs of the technology, it will not only generate electricity it will also extend the economic life of wells, making them more profitable, said Greg Rowe, a production manager with Continental Resources. [...]"<
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.
Duane Tilden's insight:
>" [...] 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?" "<
In a fairly radical departure from the principles that normally govern hydroelectric power generation, Austrian engineer Franz Zotlöterer has constructed a low-head power plant that makes use of the kinetic energy inherent in an artificially induced vortex. The water's vortex energy is collected by a slow moving, large-surface water wheel, making the power station transparent to fish - there are no large pressure differences built up, as happens in normal turbines.
Duane Tilden's insight:
>" [...] The aspect of the power plant reminds a bit of an upside-down snail - through a large, straight inlet the water enters tangentially into a round basin, forming a powerful vortex, which finds its outlet at the center bottom of the shallow basin. The turbine does not work on pressure differential but on the dynamic force of the vortex. Not only does this power plant produce a useful output of electricity, it also aerates the water in a gentle way. Indeed, the inventor was looking for an efficient way to aerate the water of a small stream as he hit upon this smart idea of a plant that not only gives air to the medium but also takes from it some of the kinetic energy that is always inherent in a stream.
[...] Zotlöterer's results are quite respectable. The cost of construction for his plant was half that of a conventional hydroelectric installation of similar yield and the environmental impact is positive, instead of negative.
The diameter of the vortex basin is 5 meters.
The head - difference between the two water levels - is 1,6 meters.
The turbine produced 50.000 kWh in its first year of operation.
Construction cost was 57.000 Euro [...] "<
NASA's Jet Propulsion Laboratory, Pasadena, California, has licensed patents on high-temperature thermoelectric materials to Evident Technologies, Troy, New York, which provides these kinds of materials and related power systems.
Duane Tilden's insight:
>" [...] Thermoelectric materials convert heat into electricity. For example, by using this technology, waste-heat from a car could potentially be fed back into the vehicle and used to generate electricity. This would increase efficiency and deliver low-cost solutions for harvesting waste heat.
"The licensed technology could be applied to convert heat into electricity in a number of waste heat recovery applications, including automobile exhaust and high-temperature industrial processes such as ceramic and glass processing plants," said Thierry Caillat, task leader for the thermoelectrics team at JPL.
JPL has a long history of high-temperature thermoelectric development driven by the need for space mission power in the absence of sunlight. Many space probes that leave Earth's orbit use thermoelectrics as their electrical power source. [...]"<
Shore Hotel in Santa Monica, California, is a luxury establishment with an energy storage system and fast DC electric vehicle (EV) charging -- reportedly, the first one in the US to have this setup. It is expected that the lithium-ion energy storage system will help it reduce electricity demand charges by 50%. Over time, that savings
Duane Tilden's insight:
So what is the connection between energy storage and EV charging? When an EV is plugged into a charger, electricity demand increases, so the hotel could be on the hook for a high rate for the electricity, depending on the time of day. Demand charges are based on the highest rate for 15 minutes in a billing cycle. So, obviously, a business would want to avoid spikes in electricity usage so it would not have to pay that rate.
That’s where the energy storage comes in. When there is a spike, electricity can be used from the energy storage system, instead of from a utility’s electricity. Avoiding demand charges in this way, as noted above, can thus help businesses save money. [...]"<
When a heat wave rolls in, most people crank up their AC units and turn on their sprinklers to cool off. But when the heat decides to settle in, just like it did repeatedly in Texas over the last several summers, the combination of a high demand for electricity and dwindling water supply can start a vicious circle. That’s because power plants use water for cooling equipment and a lack …
Duane Tilden's insight:
>" [...] 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 (blue and gray building center left).
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. [...]"<
Figure 1: Radial Outflow Turbine Generator - Organic Rankine Cycle - ORC Turbine (1) Existing oil and gas wells offer access to untapped sources of heat which can be converted to electricity or used for other energy intensive purposes. This includes many abandoned wells, which can be reactivated as power sources. These wells, in many cases "stranded…
With 88 projects from coast to coast, it might be the biggest grid edge R&D effort ever. Here’s how the money is going to be spent.
Duane Tilden's insight:
"[...] The Grid Modernization Multi-Year Program Plan will bring a consortium of 14 national laboratories together with more than 100 companies, utilities, research organizations, state regulators and regional grid operators. The scope of this work includes integrating renewable energy, energy storage and smart building technologies at the edges of the grid network, at a much greater scale than is done today.
That will require a complicated mix of customer-owned and utility-controlled technology, all of which must be secured against cyberattacks and extreme weather events. And at some point, all of this new technology will need to become part of how utilities, grid operators, regulators, ratepayers and new energy services providers manage the economics of the grid.
DOE has already started releasing funds to 10 “pioneer regional partnerships,” or “early-stage, public-private collaborative projects [...]
The projects range from remote microgrids in Alaska and grid resiliency in New Orleans, to renewable energy integration in Vermont and Hawaii, and scaling up to statewide energy regulatory overhauls in California and New York. Others are providing software simulation capabilities to utilities and grid operators around the country, or looking at ways to tie the country’s massive eastern and western grids into a more secure and efficient whole.
Another six “core” projects are working on more central issues, like creating the “fundamental knowledge, metrics and tools we’re going to need to establish the foundation of this effort,” he said.
Those include technology architecture and interoperability, device testing and validation, setting values for different grid services that integrated distributed energy resources (DERs) can provide, and coming up with the right sensor and control strategy to balance costs and complexity.
Finally, the DOE has identified six “cross-cutting” technology areas that it wants to support, Patricia Hoffman, assistant secretary of DOE’s Office of Electricity Delivery and Energy Reliability, noted in last week’s conference call. Those include device and integrated system testing, sensing and measurement, system operations and controls, design and planning tools, security and resilience, and institutional support for the utilities, state regulators and regional grid operators that will be the entities that end up deploying this technology at scale.
Much of the work is being driven by the power grid modernization needs laid out in DOE’s Quadrennial Energy Review, which called for $3.5 billion in new spending to modernize and strengthen the country’s power grid, while the Quadrennial Technology Review brought cybersecurity and interoperability concerns to bear.[...]
DOE will hold six regional workshops over the coming months to provide more details, Danielson said. We've already seen one come out this week -- the $18 million in SunShot grants for six projects testing out ways to bring storage-backed solar power to the grid at a cost of less than 14 cents per kilowatt-hour.
“We can’t look at one attribute of the grid at a time,” he said. “We’re not just looking for a secure grid -- we’re looking for an affordable grid, a sustainable grid, a resilient grid.” And one that can foster renewable energy and greenhouse gas reduction at the state-by-state and national levels. [...]
In its first analysis of the levelized cost of storage, Lazard finds some promising economic trends.
Duane Tilden's insight:
"[...] “Although in its formative stages, the energy storage industry appears to be at an inflection point, much like that experienced by the renewable energy industry around the time we created the LCOE study eight years ago,” said George Bilicic, the head of Lazard's energy and infrastructure group, in a release about the report.
Lazard modeled a bunch of different use cases for storage in front of the meter (replacing peaker plants, grid balancing, and equipment upgrade deferrals) and behind the meter (demand charge reduction, microgrid support, solar integration). It also modeled eight different technologies, ranging from compressed-air energy storage to lithium-ion batteries.
"As a first iteration, Lazard has captured the complexity of valuating storage costs pretty well. Unlike with solar or other generation technologies, storage cost analysis needs to account for not just different technologies, but also location and application, essentially creating a three-dimensional grid," said Ravi Manghani, GTM Research's senior storage analyst.
In select cases, assuming best-case capital costs and performance, a handful of storage technologies rival conventional alternatives on an unsubsidized basis in front of the meter. Using lithium-ion batteries for frequency regulation is one example. Deploying pumped hydro to integrate renewables into the transmission system is another. [...]
The global desalination capacity will double by 2020, according to a new analysis by Frost & Sullivan.
Duane Tilden's insight:
"[...] rapid industrialization and urbanization have increased water scarcity in many parts of the world. As drought conditions intensify, desalination is expected to evolve into a long-term solution rather than a temporary fix.
Technology providers can capitalize on this immense potential by developing cost-effective and sustainable solutions, the consulting firm said.
The report states that the global desalination market earned revenues of $11.66 billion in 2015, and this figure is estimated to reach $19.08 billion in 2019. More than 17,000 desalination plants are currently in operation in 150 countries worldwide, a capacity that is predicted to double by the end of the decade.
“Environmentally conscious countries in Europe and the Americas are hesitant to practice desalination owing to its harsh effects on sea water,” noted Vandhana Ravi, independent consultant for Frost & Sullivan’s Environment and Building Technologies unit. “Eco-friendly desalination systems that do not use chemicals will be well-received among municipalities in these regions.”
The report highlights several factors that are holding back adoption in some parts of the world, including lack of regulatory support and the high cost of desalination. The thermal desalination process also releases significant volumes of highly salty liquid brine back into water bodies, impacting the environment. Brine disposal will remain a key challenge until a technology upgrade resolves the issue. [...]"
The oil cartel is living in a time-warp, seemingly unaware that global energy
Duane Tilden's insight:
"...OPEC says battery costs may fall by 30-50pc over the next quarter century but doubts that this will be enough to make much difference, due to "consumer resistance".
This is a brave call given that Apple and Google have thrown their vast resources into the race for plug-in vehicles, and Tesla's Model 3s will be on the market by 2017 for around $35,000.
Ford has just announced that it will invest $4.5bn in electric and hybrid cars, with 13 models for sale by 2020. Volkswagen is to unveil its "completely new concept car" next month, promising a new era of "affordable long-distance electromobility."
The OPEC report is equally dismissive of Toyota's decision to bet its future on hydrogen fuel cars, starting with the Mirai as a loss-leader. One should have thought that a decision by the world's biggest car company to end all production of petrol and diesel cars by 2050 might be a wake-up call.
Goldman Sachs expects 'grid-connected vehicles' to capture 22pc of the global market within a decade, with sales of 25m a year, and by then - it says - the auto giants will think twice before investing any more money in the internal combustion engine. Once critical mass is reached, it is not hard to imagine a wholesale shift to electrification in the 2030s. [...]
A team of Cambridge chemists says it has cracked the technology of a lithium-air battery with 90pc efficiency, able to power a car from London to Edinburgh on a single charge. It promises to cut costs by four-fifths, and could be on the road within a decade.
There is now a global race to win the battery prize. The US Department of Energy is funding a project by the universities of Michigan, Stanford, and Chicago, in concert with the Argonne and Lawrence Berkeley national laboratories. The Japan Science and Technology Agency has its own project in Osaka. South Korea and China are mobilising their research centres.
A regulatory squeeze is quickly changing the rules of global energy.The Grantham Institute at the London School of Economics counts 800 policies and laws aimed at curbing emissions worldwide.
Goldman Sachs says the model to watch is Norway, where electric vehicles already command 16.3pc of the market. The switch has been driven by tax exemptions, priority use of traffic lanes, and a forest of charging stations.
California is following suit. It has a mandatory 22pc target for 'grid-connected' vehicles within ten years. New cars in China will have to meet emission standards of 5 litres per 100km by 2020, even stricter than in Europe. [...]
In the meantime, OPEC revenues have crashed from $1.2 trillion in 2012 to nearer $400bn at today's Brent price of $36.75, with fiscal and regime pain to match.
This policy has eroded global spare capacity to a wafer-thin 1.5m b/d, leaving the world vulnerable to a future shock. It implies a far more volatile market in which prices gyrate wildly, eroding confidence in oil as a reliable source of energy.
The more that this Saudi policy succeeds, the quicker the world will adopt policies to break reliance on its only product. As internal critics in Riyadh keep grumbling, the strategy is suicide.
Saudi Arabia and the Gulf states are lucky. They have been warned in advance that OPEC faces slow-run off. The cartel has 25 years to prepare for a new order that will require far less oil.
If they have any planning sense, they will manage the market to ensure crude prices of $70 to $80. They will eke out their revenues long enough to control spending and train their people for a post-petrol economy, rather than clinging to 20th Century illusions.
Sheikh Ahmed Zaki Yamani, the former Saudi oil minister, warned in aninterview with the Telegraph fifteen years ago that this moment of reckoning was coming and he specifically cited fuel-cell technologies.
"Thirty years from now there will be a huge amount of oil - and no buyers. Oil will be left in the ground. The Stone Age came to an end, not because we had a lack of stones."
They did not listen to him then, and they are not listening now."
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
Duane Tilden's insight:
>" 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. [...]"<
Efficient Drivetrains and American Repower are partnering to convert a fleet of six armored vans to run on compressed natural gas with a plug-in hybrid.
Duane Tilden's insight:
>"When hauling around massive amounts of money and valuables around Southern California, security is generally a much bigger concern than fuel economy. However, the need for vehicles to become more efficient is hitting every segment, even armored vans. That's why Efficient Drivetrains Inc. and North American Repower are teaming up to convert six of these 26,000-pound behemoths run on natural gaswith a plug-in hybrid offering additional help. The first one should be hauling riches for Sectran Security around Los Angeles in 2016.
>"Press Release:North American Repower and Efficient Drivetrains, Inc. to Deliver First PHEV-RNG Armored Truck
Collaboration reduces emissions by 99.9 percent
OCEANSIDE, Calif. & MILPITAS, Calif.--(BUSINESS WIRE)--Two global leaders in developing and manufacturing advanced transportation vehicles have teamed up to manufacture a first-of-its-kind fleet of Class-5 armored vehicles that combine the benefits of Renewable Natural Gas (RNG) and zero emission Plug-In Hybrid Electric Vehicle (PHEV) technology.
"We're excited to be partnering with EDI on this breakthrough innovation"
North American Repower—California's leading natural gas engine management and conversion technology company— and Efficient Drivetrains, Inc.—a global leader in developing high-efficiency Plug-in Hybrid Electric Vehicle solution—will convert a fleet of six 26,000 pound, Class-5 medium-duty armored vehicles operated by Sectran Security into PHEV vehicles that run on electricity and renewable natural gas—known as "Zero Emission with Range Extension" vehicles. The collaboration supports the dramatic acceleration in California toward a zero emissions environment. Today, the Sectran Security trucks make frequent stops as part of their highly congested urban routes. At each stop, the engines are kept idling for security purposes, but now risk violating California's strict diesel idling regulations, which prohibit idling the engine for more than five minutes. With the modernized trucks, Sectran can completely eliminate engine idling by operating in all-electric mode during stop-and-go operations on urban routes and in hybrid-mode during highway operations. When complete, the vehicles possess impressive performance statistics—the demonstration trucks will enable Sectran to reduce annual diesel consumption by 31,000+ gallons, significantly reduce annual fuel costs, and reduce emissions by 99.9 percent. [...]"<
Thirty five years ago concerned ratepayers challenged BC Hydro, the BC Utilities Commission and the Provincial government to admit that electricity conservation and small power projects were preferable to flooding the farm lands of the Peace Valley. Building another dam was not the answer then, and it is not the answer today.
Duane Tilden's insight:
>" Roger Bryenton & Associates, 2015 [...] Conservation, plus a variety of smaller, low impact green projects can save and produce more electricity at a lower cost, with less risk, than Site C.
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.
Duane Tilden's insight:
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. [...]"<
Where's the middle ground between having a small solar charger for your gadgets, and having a rooftop solar array capable of powering your entire house? The UNplug might know.
Duane Tilden's insight:
>" [...] The UNplug solar controller was invented by Markus Löffler in response to his own power blackout experience, where several days without electricity meant a lot of spoiled food. Löffler, an entrepreneur and software engineer living in Altadena, California, developed the UNplug device to serve as a simple and inexpensive way to begin going solar, because it serves as the brain of a micro-solar system, starting as small as a single solar panel and a small battery bank. [...]
During the day, UNplug feeds electricity from the solar panel into the appliances connected to it, and charges the battery bank, and then when the sun goes down, it seamlessly switches over those devices to using grid power. In the event of a blackout, UNplug then powers those same appliances from the battery bank, allowing certain crucial electricity needs to continue to be met during an outage.
The UNplug could allow homes to take at least some of their daily electrical loads off the grid, such as the fridge or other household devices, while also serving as an uninterruptible power supply (UPS) in the event of a power outage. The device doesn't function all by itself, of course, and requires solar panels, batteries, an inverter, and other accessories, but according to Löffler's campaign page, a small system could be set up for an additional $570 or so, on top of the cost of the UNplug, so the entire investment could be under $1000. (His shopping list is here.) [...]"<
"In the United States, petroleum is by far the most-consumed transportation fuel. But recently the share of fuels other than petroleum for U.S. transportation has increased to its highest level since 1954, a time when the use of coal-fired steam locomotives was declining and automobile use was growing rapidly."
Duane Tilden's insight:
>" [...] After nearly 50 years of relative stability at about 4%, the nonpetroleum share started increasing steadily in the mid-2000s, reaching 8.5% in 2014. Of the nonpetroleum fuels used for transportation, fuel ethanol has grown most rapidly in recent years, increasing by nearly one quadrillion British thermal units (Btu) between 2000 and 2014. Nearly all of the ethanol consumed was blended into gasoline in blends of 10% or less, but a small amount was used in vehicles capable of running on higher blends as the availability of those flexible-fuel vehicles grew. Consumption of biodiesel, most of it blended into diesel fuel for use in trucks and buses, grew to more than 180 trillion Btu by 2014.
In 2014, transportation use of natural gas reached a historic high of 946 trillion Btu, 3.5% of all natural gas used in the United States. Transportation natural gas is mostly used in the operation of pipelines, primarily to run compressor stations and to deliver natural gas to consumers. Natural gas used to fuel vehicles, although a much smaller amount, has more than doubled since 2000.
Electricity retail sales to the transportation sector grew more than 40% from 2000 through 2014, although sales have declined slightly since 2007. Electricity for transportation is mostly sold to railroads and railways. However, this increase does not include the consumption of electricity in electric vehicles that are not used in mass transit, because charging stations for these types of vehicles are likely associated with meters on residential, commercial, or industrial customer sites where this specific use may not be differentiated from other uses. [...]"<
The U.S. Department of Energy hopes to create a more efficient turbine that uses CO2 to make electricity
Duane Tilden's insight:
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
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. [...]"<