Researchers find new cold-tolerant, lipid-producing alga in Rocky Mountains

Researchers from the University of Minnesota report finding a new strain of cold-tolerant, lipid-producing yellow-green algae-heterococcus sp. DN1-in the snow fields of the Rocky Mountains. They report their finding in a paper accepted in the journal Biotechnology Progress.

Algae that can grow in extreme conditions and accumulate lipids are of great interest to industry. H. sp. DN1 was found to grow at temperatures approaching freezing and to accumulate large intracellular stores of lipids.

The team found that as H. sp. DN1 produces the highest quantity of lipids when grown undisturbed with high light in low temperatures, it is a potential source of lipids for human nutrition when grown undisturbed, and it has an ideal lipid profile for biofuel production when stressed.

We have isolated and characterized a new cold-tolerant lipid-producing strain of algae from the Rocky Mountains in Colorado, US. This may have implications for the commercial production of algal lipids at northern latitudes where the culture of other algal species is limited or impossible.

-Dr. David Nelson, lead author

Resources

• David Nelson, Sinafik Mengistu, Paul Ranum, Gail Celio, Mara Mashek, Douglas Mashek, Paul Lefebvre (2013) New lipid-producing, cold-tolerant yellow-green alga isolated from the Rocky Mountains of Colorado, Biotechnology Progress doi: 10.1002/btpr.1755

http://www.greencarcongress.com/2013/06/nelson-20130602.htm

USGS finds US aquifers being drawn down at accelerating rate

A new US Geological Survey study finds that US aquifers are being drawn down at an accelerating rate. Groundwater Depletion in the United States (1900-2008) comprehensively evaluates long-term cumulative depletion volumes in 40 separate aquifers (distinct underground water storage areas) in the United States, bringing together reliable information from previous references and from new analyses.

From 1900 to 2008, US aquifers decreased by more than twice the volume of water found in Lake Erie. Groundwater depletion in the US in the years 2000-2008 can also explain more than 2% of the observed global sea-level rise during that period, according to USGS.

Since 1950, the use of groundwater resources for agricultural, industrial, and municipal purposes has greatly expanded in the United States. When groundwater is withdrawn from subsurface storage faster than it is recharged by precipitation or other water sources, the result is groundwater depletion. The depletion of groundwater has many negative consequences, including land subsidence, reduced well yields, and diminished spring and stream flows.

While the rate of groundwater depletion across the country has increased markedly since about 1950, the maximum rates have occurred during the most recent period of the study (2000-2008), when the depletion rate averaged almost 25 cubic kilometers per year. For comparison, 9.2 cubic kilometers per year is the historical average calculated over the 1900-2008 timespan of the study.

One of the best known and most investigated aquifers in the US is the High Plains (or Ogallala) aquifer. It underlies more than 170,000 square miles of the Nation's midsection and represents the principal source of water for irrigation and drinking in this major agricultural area. Substantial pumping of the High Plains aquifer for irrigation since the 1940s has resulted in large water-table declines that exceed 160 feet in places.

The study shows that, since 2000, depletion of the High Plains aquifer appears to be continuing at a high rate. The depletion during the last 8 years of record (2001-2008, inclusive) is about 32% of the cumulative depletion in this aquifer during the entire 20th century. The annual rate of depletion during this recent period averaged about 10.2 cubic kilometers, roughly 2% of the volume of water in Lake Erie.

Groundwater is one of the Nation's most important natural resources. It provides drinking water in both rural and urban communities. It supports irrigation and industry, sustains the flow of streams and rivers, and maintains ecosystems. Because groundwater systems typically respond slowly to human actions, a long-term perspective is vital to manage this valuable resource in sustainable ways.

-Suzette Kimball, acting USGS Director

http://www.greencarcongress.com/2013/05/usgs-20130521.htm

USGS, DOE, and BOEM study delivers new insights on gas hydrates in Gulf of Mexico

Scientists have returned from a 15‚Äëday research expedition in the northern Gulf of Mexico with the best high-resolution seismic data and imagery yet obtained of sediments with high gas hydrate saturations.

The expedition and the data and imagery collected resulted from long-standing cooperation between the US Department of the Interior's US Geological Survey (USGS) and Bureau of Ocean Energy Management (BOEM) and the US Department of Energy (DOE). This collaboration aims to advance scientific understanding of gas hydrates, a potential future energy resource.

This high-resolution image was collected during a seismic cruise to study locations with high concentrations of gas hydrate in the northern Gulf of Mexico in April and May 2013. The data were collected at the Walker Ridge location, where 2009 drilling at the site of the well (shown in red revealed) the distribution of gas hydrates and methane gas in the sediments. The water depth at the well is 6,562 feet (2,000 meters), and the red and blue colors shown within the image correspond to sediment layers, which mostly dip westward. Sand layers with high concentrations of gas hydrate are marked, but hydrate also occurs elsewhere in this sedimentary section. Click to enlarge. Source: USGS.

Gas hydrates are ice-like substances formed when certain gases combine with water at specific pressures and temperatures. Deposits of gas hydrates are widespread in marine sediments beneath the ocean floor and in sediments within and beneath permafrost areas, where pressure-temperature conditions keep the gas trapped in the hydrate structure. Methane is the gas most often trapped in these deposits, making gas hydrates a potentially significant source for natural gas around the world.

This expedition represents a significant milestone. The data and imagery provide insight into the entire petroleum system at each location, including the source of gas, the migration pathways for the gas, the distribution of hydrate-bearing sediments, and the traps that hold the hydrate and free gas in place. The USGS has a globally recognized research effort studying gas hydrates in settings around the world, and this project combines our unique expertise with that of other agencies to advance research on this potential future energy resource.

- USGS Energy Resources Program Coordinator Brenda Pierce

The recently completed expedition was planned jointly by USGS, DOE, and BOEM, and was executed by USGS. Using low-energy seismic sources, USGS scientists collected details about the nature of the gas hydrate reservoirs and about geologic features of the sediment between the reservoirs and the seafloor. The new data also provide information about how much gas hydrate exists in a much broader area than can be determined from using standard industry seismic data, which is typically designed to image much deeper geologic units.

The high-resolution nature of the data acquired through this interagency project will uniquely inform the BOEM effort to assess the resource potential of gas hydrates on the US Outer Continental Shelf.

-Renee Orr, Chief, Strategic Resources Office, BOEM

The data were collected at two locations in the Gulf of Mexico where the three federal agencies partnered with an industry consortium to conduct a drilling expedition in 2009. That expedition discovered gas hydrate filling between 50 and 90 percent of the available pore space between sediment grains in sandy layers in the subsurface. These reservoirs are expected to be representative of the 6,700 trillion cubic feet of gas that BOEM estimates is housed in gas hydrates in sand-rich reservoirs in the northern Gulf of Mexico.

The new data are being used to refine estimates of the nature, distribution, and concentration of gas hydrate in the vicinity of the 2009 drill sites. This will help assess how useful specialized seismic data may be to estimating hydrate saturations in deepwater sediments.

In coming years, the three agencies will continue their collaborative investigation of gas hydrates in the northern Gulf of Mexico and other locations across the world.

http://www.greencarcongress.com/2013/05/usgs-20130514.htm

Study concludes microbial lipids can be commercially viable source of biodiesel

Researchers from Wageningen University, The Netherlands, have concluded that "although quite some work still has to be done", microbial lipids-i.e., lipids from yeasts and fungi-have the potential to be tomorrow's source of biodiesel. Their analysis is published in the journal Biofuels, Bioproducts and Biorefining.

In the search for new transport fuels from renewable resources, biodiesel from microbial lipids comes into view. We have evaluated the lipid yield and energy use of a process for production of biodiesel from agricultural waste using lipid-accumulating yeast and fungi. We included different bioreactors for submerged and solid-state fermentation in our evaluation.

Using existing kinetic models, we predict lipid yields on substrate between 5% and 19% (w/w), depending on the culture system. According to the same models, improvement of the yield to 25-30% (w/w) is possible, for example by genetic modification of the micro-organisms. The net energy ratio of the non-optimized systems varies between 0.8 and 2.5 MJ produced per MJ used; energy use for pre-treatment and for oxygen transfer are most important. For the optimized systems, the net energy ratio increases to 2.9-5.5 MJ produced per MJ used, which can compete very well with other biofuels such as bioethanol or algal biodiesel.

-Meeuwse et al.

Resources

• Meeuwse, P., Sanders, J. P.M., Tramper, J. and Rinzema, A. (2013), Lipids from yeasts and fungi: Tomorrow's source of biodiesel?. Biofuels, Bioprod. Bioref. doi: 10.1002/bbb.1410

http://www.greencarcongress.com/2013/05/lipids-20130510.htm

Shell moves forward with ultra-deepwater Stones project in Gulf of Mexico; deepest production facility in world

Royal Dutch Shell plc (Shell) made a final investment decision in the Stones ultra-deepwater project, a Gulf of Mexico oil and gas development expected to host the deepest production facility in the world. This decision sets in motion the construction and fabrication of a floating production, storage, and offloading (FPSO) vessel and subsea infrastructure.

The Stones field is located in 9,500 feet (2,896 meters) of water, approximately 200 miles (320 kilometers) southwest of New Orleans, Louisiana, and was discovered in 2005. The project encompasses eight US Federal Outer Continental Shelf lease blocks in the Gulf of Mexico's Lower Tertiary geologic trend. Shell has been one of the pioneers in the Lower Tertiary, establishing first production in the play from its Perdido Development.

Location of Stones. Click to enlarge.

The Stones development will start with two subsea production wells tied back to the FPSO vessel, followed later by six additional production wells. This first phase of development is expected to have annual peak production of 50,000 boe/d from more than 250 million boe of recoverable resources. The Stones field has significant upside potential and is estimated to contain more than 2 billion boe of oil in place, according to Shell.

This important investment demonstrates our ongoing commitment to usher in the next generation of deepwater developments, which will deliver more production growth in the Americas.

-John Hollowell, Executive Vice President for Deepwater, Shell Upstream Americas

An FPSO design was selected to develop and produce this ultra-deepwater discovery while addressing the relative lack of infrastructure, seabed complexity, and unique reservoir properties. With an FPSO, tankers will transport oil from the Stones FPSO to US refineries, and gas will be transported by pipeline. Features of the design include:

• A turret with a disconnectable buoy will allow the FPSO vessel to weathervane in normal conditions and to disconnect from the well system and sail to safe areas in the event of adverse weather conditions.

• A lazy wave riser configuration will be used, consisting of a steel catenary riser with buoyancy added with an arch bend to decouple the FPSO dynamic motions and subsequently increase riser performance.

• The ultra-deepwater mooring system holding the FPSO on station uses a combination of polyester rope and chain.

• Multiphase seafloor pumping is planned for use in a later phase to pump oil and gas from the seabed to the FPSO, increasing recoverable volumes and production rates.

The launch of the Stones development is a key milestone for Shell as it continues to grow deepwater exploration and development in the Gulf of Mexico, having made progress recently on the Mars-B development project with the arrival of the Olympus tension leg platform. Shell is also in the concept selection phase for the Appomattox and Vito discoveries in the Gulf of Mexico.

Shell holds 100% interest and will operate the Stones development.

http://www.greencarcongress.com/2013/05/stones-20130508.htm

ES&T editorial calls Keystone XL a "pipeline to nowhere"

Editor-in Chief of the ACS journal Environmental Science & Technology Dr. Jerald Schnoor, also a professor in the departments of civil & environmental engineering and occupational & environmental health at the University of Iowa, has written an editorial for the journal in which he calls the Keystone XL pipeline a "pipeline to nowhere".

Use of coal, oil, and natural gas has to stop (in that order). But "dirty" oil, emanating from oil sands (a.k.a., tar sands) with a significantly higher carbon footprint than conventional oil, deserves a place at the front of the line. The proposed Keystone XL pipeline would enable development of oil sands from Alberta, Canada, to the U.S., but this dog will not hunt. It is a pipeline to nowhere-a dead end in our economic future.

-Jerald Schnoor

Schnoor adduces five points against the building of the pipeline:

1. We do not really need the oil. "Energy efficiency is actually the key(stone) we should be focusing on. "
2. Keystone XL would add to global greenhouse gas emissions.
3. It is a slippery (and oily) slope.
4. Let Canadians decide (about pipelines in Canada for carrying the oil).
5. When do we start to stop? If not now, when?

It has been a good run, this fossil fuel age. But from the invention of steam power in the 1700s when industrial society first started to burn huge quantities of coal, the future was preordained. One cannot burn all the fossil fuels that required 300 million years to form in just a few centuries and not expect to pay consequences. The fossil fuel age has massively disrupted the balance of oxidation and reduction on earth. Thus, elemental cycles yield more oxidized products like acid rain (nitric acid, sulfuric acid) and carbon dioxide as a result.

-Jerald Schnoor

http://www.greencarcongress.com/2013/04/schnoor-20130430.htm

Honda to build wind farm to cover 100% of electricity needs of Brazil plant

Honda Automoveis do Brasil Ltda. (HAB), the Honda automobile production and sales subsidiary in Brazil, will build a wind farm in the city of Xangri-lá in Rio Grande do Sul, the southernmost state in Brazil-approximately 1,000 km (621 miles) south of HAB's automobile production plant in Sumaré, São Paulo. Equipped with nine wind power turbine units, the wind farm is expected to generate approximately 85,000 MWh of electricity per year, equivalent to HAB's annual electricity needs for automobile production.

HAB will be the first automobile manufacturer in Brazil to invest in wind power generation. Operation is due to begin in September 2014.

By generating renewable energy to cover the entire electricity needs of the plant, HAB is expecting to reduce CO₂ emissions by approximately more than 2,200 t annually. The total investment in this wind farm is expected to be approximately 100 million Brazilian reais (approximately US$50 million).

In order to evolve wind power generation business in Brazil, HAB established a new subsidiary, Honda Energy do Brasil Ltda., specialized in wind power generation business. Honda Energy do Brasil Ltda. will be responsible for the management and operation of all areas related to Honda's wind power generation business in Brazil.

http://www.greencarcongress.com/2013/04/honda-20130425.htm

Obama Administration announces 21M-acre oil and gas lease sale offshore Texas

The US Department of the Interior will offer more than 21 million acres offshore Texas for oil and gas exploration and development in a lease sale that will include all available unleased areas in the Western Gulf of Mexico Planning Area.

Proposed Lease Sale 233, scheduled to take place in New Orleans in August, will be the third offshore auction under the Administration's Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (Five Year Program). The sale builds on the first two auctions in the current Five Year Program-a 39-million-acre sale held in March, which attracted more than $1.2 billion in high bids and a 20-million-acre sale held last November that netted nearly $134 million.

The Gulf of Mexico is a cornerstone of the United States' energy portfolio.

- Secretary of the Interior Sally Jewell

Lease Sale 233 will include 3,953 blocks, covering about 21.1 million acres, located from nine to 250 miles offshore, in water depths ranging from 16 to more than 10,975 feet (5 to 3,346 meters). BOEM estimates the proposed sale could result in the production of 116 to 200 million barrels of oil and 538 to 938 billion cubic feet of natural gas.

BOEM published a Final Supplemental Environmental Impact Statement to update the environmental analysis completed for proposed Lease Sale 233 and other Western and Central Gulf of Mexico lease sales scheduled under the current Five Year Program.

The proposed terms of this sale include conditions to ensure both orderly resource development and protection of the human, marine and coastal environments. These include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species, and avoid potential conflicts associated with oil and gas development and other uses in the region.

BOEM's proposed economic terms include the same range of incentives to encourage diligent development and ensure a fair return to taxpayers as used in previous sales, with one exception. The provision for deep gas royalty relief under the Energy Policy Act of 2005 (EPAct) will sunset on May 3, 2013, and, therefore, will not be offered. Ultra-deep gas royalty relief required under EPAct will still be available.

http://www.greencarcongress.com/2013/04/doi-20130425.htm

UPS to purchase ~700 LNG trucks, build 4 refueling stations by end of 2014

UPS plans to purchase approximately 700 liquefied natural gas (LNG) trucks and to build four refueling stations by the end of 2014. Once completed, the LNG private fleet will be one of the most extensive in the US.

An initial investment of more than $18 million to build fueling stations will be supported by the purchase of the 700 LNG tractors and continued expansion of the natural gas fleet in the US. UPS already operates 112 LNG tractor trailers from fueling stations in Las Vegas, Nev.; Phoenix, Ariz., and Beaver and Salt Lake City, Utah, and has its own LNG fueling station on its property in Ontario, Calif.

New UPS-built fueling stations in Knoxville, Nashville and Memphis, Tenn., and Dallas, Texas, will serve its heavy-duty rigs traveling into adjacent states. With the addition of accessible LNG fueling stations, UPS also will add LNG trucks on routes from Dallas, Houston and San Antonio, Texas to further extend territory.

UPS was a founding Interstate Clean Transportation Corridor (ICTC) fleet partner, a group that established publicly accessible LNG fueling stations in California, Las Vegas, and Utah. The ICTC steering committee includes eight government and regulatory agencies at the local, state and national levels.

LNG is a good alternative to petroleum-based fuel for long-haul delivery fleets as it is abundant and produces reduced emissions at less cost. At UPS, we are helping to knock down some of the biggest hurdles to broad market acceptance of LNG in commercial transportation by continuing to establish vehicle demand, fuel and maintenance infrastructures. We plan expansion through infrastructure partnerships and a broader fleet in states that are leading the way to make alternative fuel vehicles economically feasible.

-Scott Davis, UPS Chairman and CEO

UPS has been operating natural gas vehicles for more than a decade. With natural gas prices 30-40% lower than imported diesel and US production gearing up, the logistics company is investing more aggressively in the natural gas infrastructure necessary to make it part of the UPS delivery network here. Beyond favorable fuel cost and domestic resource access, the industry cites 25% less CO₂ emissions.

Worldwide UPS has more than 1,000 natural gas vehicles on the road today. UPS's alternative fuel and advanced technology fleet of more than 2,600 vehicles also includes a wide array of low-emissions vehicles, including all-electrics, electric hybrids, hydraulic hybrids, propane, compressed natural gas and biomethane. Since 2000, the fleet powered by alternative fuels and technologies has driven more than 295 million miles.

http://www.greencarcongress.com/2013/04/ups-20130423.htm

GE unveils LNG In A Box system

GE Oil & Gas introduced the LNG In A Box system, a small-scale, plug-and-play, re-deployable liquefied natural gas (LNG) fueling solution based on proven technology that can help accelerate the use of natural gas as a cost-effective, cleaner transportation fuel.

The world's first commercial application of the LNG In A Box system will be for LNG fueling stations in Europe to be delivered by Luxembourg-based LNG firm Gasfin through its operating company AIR-LNG, GE announced at the 17^th International Conference & Exhibition on Liquefied Natural Gas (LNG-17) in Houston.

Each LNG In A Box unit is fully equipped with a gas pre-treatment system, cold box assembly and boil off gas compressor as well as a GE's turboexpander compressor, high-speed reciprocating compressor, electric motor, driver and control system. LNG In A Box units for Gasfin will be manufactured in the United States and will be shipped to Gasfin's LNG fueling sites in Europe.

Gasfin signed a memorandum of understanding with GE to install five LNG In A Box units serving "clusters" of LNG fueling stations. The first unit will be installed near the border of Italy and Slovenia, with the potential for an additional 25 units for expansion into Europe and the CIS countries.

In comparison to GE's Micro LNG plant announced last year (earlier post), this new system offers customers a more standardized, modular fueling solution covering an LNG production range of 10,000 - 50,000 gallons a day (16-18 tons/day). It expands GE's existing LNG portfolio and is the first available in a 10,000-gallons-a-day capacity that reduces demand-side adoption risk and requires a low CapEx and OpEx commitment.

Small-scale solutions such as the LNG In A Box system may encourage the transition of long-haul trucks from diesel fuel to LNG, GE suggests. In the case of North America, fuel savings may yield a three-year payback based on current fuel prices.

The small-scale solution also is economically suited for customers seeking a 10-50,000-gallons-a-day production capacity. Typical LNG tanks for heavy-duty vehicles hold an average of 70-150 gallons (110-240 kg), so one 10,000-gallon-a-day (17 tons/day) system would be able to fuel up to 100 trucks per day.

Previously introduced GE products include the CNG In A Box system (earlier post), a fully integrated compressed natural gas (CNG) fueling supply system offering cost-effective plug-and-play simplicity for fleet and retail fueling stations that provide CNG fuel; and the Micro LNG plant to power remote industrial locations and for fueling long haul trucks and locomotives running on LNG in the future.

http://www.greencarcongress.com/2013/04/ge-20130417.htm

Nevada Deploys First U.S. Commercial, Grid-Connected Enhanced Geothermal System

April 12, 2013

Nevada Deploys First U.S. Commercial, Grid-Connected Enhanced Geothermal System

As part of the Obama Administration's all-of-the-above energy strategy, the Energy Department recognized the nation's first commercial enhanced geothermal system (EGS) project to supply electricity to the grid.

http://www.greencarcongress.com/2013/04/egs-20130412.htm

http://energy.gov/articles/nevada-deploys-first-us-commercial-grid-con

New one-pot process for conversion of sugars to hydrocarbons

Researchers at Tohoku University have developed a one-pot process for the direct conversion of sugar and sugar polyols to n-alkanes. Their paper is featured on the cover of the journal ChemSusChem.

Click to enlarge.

High (‚â•95‚Äâ% C) yields of n-hexane and n-pentane were obtained by hydrogenolysis of aqueous sorbitol and xylitol, respectively, at 413-443‚ÄÖK [140-170 ¬∞C] by using the Ir-ReO_x/SiO₂ catalyst combined with H-ZSM-5 as a cocatalyst and n-dodecane as a cosolvent. The direct production of n-hexane from glucose or cellobiose can be achieved by using the same system.

The catalyst can be reused simply by the removal of the n-dodecane phase, which contains the product alkane, and the addition of fresh n-dodecane and substrate.

-Tamura et al.

The catalyst is used selectively to cut off OH groups of biomass-derived compounds-such as sugar polyols-through hydrogenolysis, similar to a knife cutting off the skin of a pineapple.

Resources

• Chen, K., Tamura, M., Yuan, Z., Nakagawa, Y. and Tomishige, K. (2013), One-Pot Conversion of Sugar and Sugar Polyols to n-Alkanes without CC Dissociation over the Ir-ReO_x/SiO₂ Catalyst Combined with H-ZSM-5. ChemSusChem, 6: 613-621. doi: 10.1002/cssc.201200940

http://www.greencarcongress.com/2013/04/tamura-20130408.htm

Frackers Are Losing $1.5 Billion Yearly to Leaks

Leaky pipes are the "super low-hanging fruit" of climate change.

Sean Garrett/Flickr

Of all the many and varied consequences of fracking (water contamination, injured workers, earthquakes, the list goes on) one of the least understood is so-called "fugitive" methane emissions. Methane is the primary ingredient of natural gas, and it escapes into the atmosphere at every stage of production: at wells, in processing plants, and in pipes on its way to your house. According to a new study, it could become one of the worst climate impacts of the fracking boom-and yet, it's one of the easiest to tackle right away. Best of all, fixing the leaks is good for the bottom line.

According to the World Resources Institute, natural gas producers allow $1.5 billion worth of methane to escape from their operations every year. That might sound like small change to an industry that drilled up some $66.5 billion worth of natural gas in 2012 alone, but it's a big deal for the climate: While methane only makes up 10 percent of greenhouse gas emissions (20 percent of which comes from cow farts), it packs a global warming punch 20 times stronger than carbon dioxide.

Courtesy WRI

"Those leaks are everywhere," said WRI analyst James Bradbury, so fixing them would be "super low-hanging fruit."

The problem, he says, is that right now those emissions aren't directly regulated by the EPA. In President Obama's first term, the EPA set new requirements for capturing other types of pollutants that escape from fracked wells, using technology that also, incidentally, limits methane. But without a cap on methane itself, WRI finds, the potent gas is free to escape at incredible rates, principally from leaky pipelines. The scale of the problem is hard to overstate: The Energy Department found that leaking methane could ultimately make natural gas-which purports to be a "clean" fossil fuel-even more damaging than coal, and an earlier WRI study found that fixing methane leaks would be the single biggest step the US could take toward meeting its long-term greenhouse gas reduction goals.

What's more, the solution to the problem doesn't rely on some kind futuristic, expensive technology: It's literally a matter of patching up leaky pipes.

So what's the holdup? For one thing, Bradbury says, that $1.5 billion in savings wouldn't necessarily go to the companies making investments in fixing pipes: Gas inside a pipeline is owned by the producer, but the pipeline itself is owned by an independent operator who might not see any advantage in preventing methane leaks. The other issue is detection: Methane is colorless and can be odorless, so there's no way to know when it's escaping, where, and how fast, without special equipment. Gear to simplify the detection process is beginning to crop up on the market, but without a government mandate there's less incentive for companies to invest in it. And without hard data on much methane they're losing, companies are disinclined to address the problem-especially across all of the nation's 300,000 miles of natural gas pipelines.

Or simply unwilling: A recent (debunked) report from the American Natural Gas Alliance claims the methane emissions risk is way over-hyped; an industry spokesperson said current practices were already enough to ensure that "people don't need to trade protection of air, land and water for economic advancement."

This is where the EPA needs to step in, Bradbury says. Under the Clean Air Act, the EPA could regulate all greenhouse gas emissions, which would cover not only methane but also the main climate change culprit, CO2. It could, at a minimum, require companies to monitor these emissions. And it could reward companies that take action via recognition in its fracking best-practices program, Natural Gas STAR. Finally, the EPA could provide better support to the state-level agencies that are ultimately responsible for enforcing Clean Air Act rules.

If the president is serious about tackling climate change from the Oval Office, Bradbury said, there could hardly be a better place to start than here.

"We need to be focused on solutions and not take a wait-and-see approach," he said. "You want to get these rules in place at the front end; we're already playing catch-up."

http://www.greencarcongress.com/2013/04/ypfdow-20130405.htm

http://climatedesk.org/2013/04/frackers-are-losing-1-5-billion-yearly-

Frost & Sullivan sees Europe emerging as strong regional market for medium- and heavy-duty natural gas vehicles

Europe is set to emerge as a strong regional market for medium- to heavy-duty natural gas (NG) commercial vehicles, populated by several competitors on both OEM and supplier sides, according to a new analysis by Frost & Sullivan.

Driven by energy price volatility, tightening emission norms, and the shale gas revolution in the US, the market for NG vehicles is gaining considerable momentum. Of all alternative NG technologies, compressed natural gas (CNG) and biomethane technologies pose the least pressure on existing infrastructure. By 2018, the NG market in Europe is expected to reach production levels of nearly 18,000 units.

Frost & Sullivan projects that that NG truck and bus penetration will reach an estimated 3.4% and 12.7%, respectively, by 2018.

Spark ignited technology will account for around 90% of commercially manufactured NG buses, while compressed ignition technology will dominate the liquefied natural gas (LNG) truck market with around 60% share. The heavy duty segment is set to account for 75% of NG truck sales with LNG being a dominant fuel option.

OEMs' willingness to differentiate products through technology partnerships is leading toward increasing focus on compression ignition and dual fuel technologies, according to Frost & Sullivan. Compression ignition would facilitate the use of NG vehicles for long haul application, which would compensate for the higher upfront cost-provided the fuel infrastructure and diesel NG price differential exists.

In future, the margins for module suppliers will shrink, and the same will happen for component suppliers when OEMs begin exerting pricing pressures as volumes start to grow. Duty cycle restriction of NG vehicles can be overcome through concerted strategies aimed at developing vehicles and products that deliver highest efficiencies in certain targeted vocations and duty cycles along with necessary fuel infrastructure.

This study is part of the Automotive & Transportation Growth Partnership Service program.

http://www.greencarcongress.com/2013/04/fs-20130404.htm

US DOI finalizes plan for oil shale and oil sands research, demonstration and development

Secretary of the Interior Ken Salazar last week announced the Department of the Interior's final plan for encouraging research, development and demonstration (RD&D) of oil shale and oil sands resources on Bureau of Land Management (BLM) lands in Colorado, Utah and Wyoming. (Earlier post.)

The Record of Decision (ROD) and plan amendments make some 700,000 acres in Colorado, Utah and Wyoming available for potential oil shale leasing and about 130,000 acres available for potential oil sands leasing in Utah. In November 2012, the BLM signed two additional leases for RD&D oil shale proposals to encourage industry to develop and test technologies aimed at developing oil shale resources on a commercial scale.

Under the Record of Decision, the BLM-managed lands will be available for RD&D leases of oil shale resources. Eligible companies could convert to a commercial lease after satisfying the conditions of the RD&D lease and meeting basic due diligence requirements and clean air and water requirements. The plan issued today will amend 10 of the BLM's land use plans.

The BLM will also begin soliciting public comments on proposed revisions to the commercial oil shale regulations. The proposed revisions are intended to ensure a fair return to the American taxpayer, encourage responsible development of federal oil shale resources, and evaluate necessary safeguards to protect scarce water resources and important wildlife habitat. The BLM is accepting public comments for 60 days following publication in the Federal Register, which is expected this week.

The proposed rule identifies several options for amending the royalty rates for commercial oil shale production. The BLM will consider whether to retain some flexibility to adjust royalty rates when more information is available about costs of production, energy inputs, and impacts associated with various extraction technologies.

The results of ongoing research and development activities combined with administrative flexibility in setting royalty rates will allow BLM to determine whether future applications to lease should include specified resource-protection plans and whether other aspects of the regulations need to be clarified.

Oil shale is a fine-grained sedimentary rock containing kerogen and is distinct from "shale oil." The largest known domestic oil shale deposits are in a 16,000-square mile area in the Green River formation in Colorado, Utah and Wyoming. Oil shale can be mined and heated to an extremely high temperature (retorting) in aboveground facilities, and the oil can then be separated from the resulting liquid. Oil shale also can be subjected to extreme heat and pressure while in underground formations (in situ retorting) and the resulting liquid pumped to the surface. The final oil shale plan examines surface mining with surface retort, underground mining with surface retort, and in situ retorting technologies.

Oil sands are sedimentary rocks containing a heavy hydrocarbon compound called bitumen, which can be refined into oil. Unlike the oil sands deposits in Canada, oil is not currently produced from oil sands on a commercial scale in the United States. US oil sands are hydrocarbon wet, whereas the Canadian oil sands are water wet, meaning that US oil sands would require different processing techniques. The final oil shale plan evaluates the potential impacts of various extraction methods for oil sands, including surface mining with surface retort, surface mining with solvent extraction, in situ steam injection, and in situ combustion technologies.

Resources

• Record of Decision

• Proposed revisions to oil shale regulations

http://www.greencarcongress.com/2013/03/doi-20130325.htm

KiOR ships first cellulosic diesel

KiOR, Inc., developer of a catalytic pyrolysis process to produce renewable rude oil from biomass (earlier post), has begun initial shipments of cellulosic diesel from its plant in Columbus, Mississippi. The facility is designed as an initial scale commercial facility, processing 500 bone dry tons of sustainably harvested woody biomass per day for an annual capacity of more than 13 million gallons of gasoline, diesel, and fuel oil blendstocks.

KiOR's facility uses pine wood chips previously feeding a shut down paper mill at Columbus to produce the renewable oil, which is processed into gasoline and diesel blendstocks. KiOR's renewable gasoline is the first renewable cellulosic gasoline registered by the Environmental Protection Agency for sale in the US. (Earlier post.)

With first production at Columbus, KiOR hastechnology with the potential to resurrect each and every shut downpaper mill in the country and to replace imported oil on a costeffective basis while creating American jobs. This facilitydemonstrates the efficacy of KiOR's proprietary catalyticbiomass-to-fuel process with the potential to deliver cellulosicgasoline and diesel to the US.

-Fred Cannon, KiOR's President and CEO

Studies show that KiOR fuels will have a significant reduction in lifecycle greenhouse gas emissions when compared to fossil-based fuels. KiOR fuels in today's engines can provide a carbon emissions profile comparable to or better than electric cars run off the US electric grid, KiOR says.

http://www.greencarcongress.com/2013/03/kior-20130318.htm

JOGMEC confirms first offshore production of methane from methane hydrates

Japan Oil, Gas and Metals National Corporation (JOGMEC) has confirmed offshore production of methane from methane hydrate layers under the Daini-Atsumi Knoll (seamount) in the eastern Nankai trough off the coast of central Japan.

Conceptual diagram of the first offshore methane hydrate production test. Source: METI. Click to enlarge.

Although the first offshore production test is not commercial production and is very much an experimental research operation, JOGMEC said, it marks a milestone in the R&D of methane hydrate as a resource. Valuable data, including the dissociation behavior of methane hydrate under the sea floor, impact to the surrounding environment, and so on, will be obtained through the testing.

If the production test is successful at the end, JOGMEC will proceed with a second offshore production test (Phase 2) and establish the technological platform toward future commercial production (Phase 3), which is scheduled from FY2016 until FY2018.

Methane hydrate is an ice-like material in which methane molecules and water molecules combine and form under the condition of high pressure and low temperature.

Japan initiated its Methane Hydrate R&D Program in 2001, beginning seismic surveys and exploitation drillings in the eastern Nankai trough.

The methane hydrate in place in that area is equivalent to approximately 40 tcf (approximately 1.1 trillion m³) of methane-equivalent to around eleven years of the amount of LNG imported into Japan.

Methane hydrate concentrated zones, the zones where methane hydrate is concentrated and which are expected to be possible targets for future resource development, occupy one-sixth of the total area and contain the amount of methane hydrate equivalent to approximately 20 tcf of methane gas, which is a half of the total amount of methane hydrate in place. However, usable resource amount is depending on the amount to be practically recovered.

Resources

• Assessment of the Resource Potential of Methane Hydrate in the Nankai Trough, Offshore Central Japan

http://www.greencarcongress.com/2013/03/jogmec-20130313.htm

China-US team concludes duckweed biorefineries can be cost-competitive with petroleum-based processes

Researchers from the US and China have determined that a duckweed biorefinery producing a range of gasoline, diesel and kerosene products can be economically competitive with petroleum-based processes, even in some cases without environmental legislation that penalizes greenhouse gas emissions. A paper describing their analysis of four different scenarios for duckweed biorefineries is published in the ACS journal Industrial & Engineering Chemistry Research.

Duckweed, an aquatic plant that floats on or near the surface of still or slow-moving freshwater, is attractive as a raw material for biofuel production. It grows fast, thrives in wastewater that has no other use, does not impact the food supply and can be harvested more easily than algae and other aquatic plants. However, few studies have been done on the use of duckweed as a raw material for biofuel production.

The team, comprising researchers from Princeton University; Peking University; Institute of Process Engineering, Chinese Academy of Sciences; and PetroChina company, investigated four different thermochemical pathways for the production of gasoline, diesel, and kerosene from gasified duckweed synthesis gas as the intermediate:

• Low-temperature and high-temperature Fischer‚àíTropsch processes (LTFT and HTFT) using both iron and cobalt based catalysts. Clean syngas is converted to hydrocarbons via cobalt or iron-based catalysts operating at either low or high temperature. The residue/wax produced from FT synthesis is directed to a hydrocracker, and the vapor phase C3‚àíC22 hydrocarbons are sent for further upgrading.

• Methanol to hydrocarbons via the methanol-to-gasoline (MTG) or methanol-to-olefins (MTO) processes. The hydrocarbons are refined into the final liquid products using ZSM-5 catalytic conversion, oligomerization, alkylation, isomerization, hydrotreating, reforming, and hydrocracking.

Fischer‚àíTropsch (FT) synthesis flowsheet. Credit: ACS, Baliban et al. Click to enlarge.	Methanol synthesis and upgrading flowsheet. Credit: ACS, Baliban et al. Click to enlarge.

The team developed a process synthesis framework to select the refining pathway that will produce the liquid fuels at the lowest possible cost. The used the synthesis framework to determine the effect of refinery capacity and liquid fuel composition on the overall system cost, the refinery topological design, the process material/energy balances, and the lifecycle greenhouse gas emissions.

The researchers used four case studies focused on two target capacities (i.e., 1,000 and 5,000 bpd) and two product compositions (i.e., unrestricted and US demand ratios of gasoline, diesel, and kerosene) to demonstrate the capability of the process synthesis framework and determine the process design that has the lowest overall cost.

The price of crude oil for which the duckweed BTL refineries will be competitive is $100/bbl for the 1 kBD unrestricted study, $69/bbl for the 5 kBD unrestricted study, $105/bbl for the 1 kBD US ratio study, and $72/bbl for the 5 kBD US ratio study. An important highlight for these four studies is the strong use of methanol synthesis opposed to FT synthesis. The lack of inert production during methanol synthesis allows for the use of a large internal synthesis gas loop and less complex synthesis gas conversion design within the refinery. The methanol can be readily converted to gasoline, diesel, and kerosene using a ZSM- 5 catalyst.

A parametric analysis on the duckweed purchase price indicates that there exists a threshold price of duckweed above which the refinery will no longer be economically competitive with crude oil refining. This threshold level for duckweed purchase depends on the desired refinery capacity and will decrease as the capacity decreases.

If crude oil was priced around $105/bbl, then the 1 kBD refineries would be economically competitive with a duckweed purchase price of $50/dry metric ton. A reduction in the duckweed purchase price to $30/dry metric ton will make the 1 kBD duckweed refineries competitive at crude prices above $95/bbl. For the 5 kBD refineries, the process synthesis framework demonstrates the economic viability at a crude price above $72/bbl for duckweed purchase prices at $50/dry metric ton. If this purchase price was raised to $70/dry metric ton, the refineries would remain competitive at crude priced above $82/bbl.

-Baliban et al.

The US National Science Foundation and the Chinese Academy of Sciences provided funding for the research.

Resources

• Richard C. Baliban, Josephine A. Elia, Christodoulos A. Floudas, Xin Xiao, Zhijian Zhang, Jie Li, Hongbin Cao, Jiong Ma, Yong Qiao, and Xuteng Hu (2013) Thermochemical Conversion of Duckweed Biomass to Gasoline, Diesel, and Jet Fuel: Process Synthesis and Global Optimization. Industrial & Engineering Chemistry Research doi: 10.1021/ie3034703

http://www.greencarcongress.com/2013/03/arpa-e-to-issue-new-funding-op

http://www.greencarcongress.com/2013/03/duckweed-20130307.htm

$1.3B methanol plant slated for South Louisiana

Louisiana Governor Bobby Jindal, South Louisiana Methanol (SLM) CEO Barry Williamson and Todd Corp. Group CEO Jon Young announced that South Louisiana Methanol LP will invest $1.3 billion in a new methanol production facility on the banks of the Mississippi River in St. James Parish. The South Louisiana Methanol site will be the largest of its kind in North America.

Austin, Texas-based Zero Emission Energy Plant Ltd. (ZEEP) and New Zealand-based Todd Corp. are joint owners of the project, which will result in a world-scale methanol plant. The SLM methanol facility will be located in the Port of South Louisiana district, with access to interstate and intrastate natural gas and carbon dioxide pipelines.

As a liquid hydrocarbon product, methanol is easily distributed as an intermediate feedstock for chemical manufacturers in the Gulf Coast region and to foreign markets. ZEEP and Todd Corp. chose St. James Parish for the new facility because of the state's strong business climate and the high inventories and inexpensive price of natural gas in Louisiana, as well as the area's strategic shipping location at the Port of South Louisiana-the largest port in the Western Hemisphere by capacity. Since 2008, more than $32 million in investments and upgrades have been made to the Port.

LED began working with ZEEP on the South Louisiana Methanol project in February 2012. To secure the project, the state will offer an incentives package that includes a $5 million performance-based grant for infrastructure costs, and services of Louisiana's workforce development program, LED FastStart. In addition, the company is expected to utilize the state's Quality Jobs and Industrial Tax Exemption programs.

Construction of the project will begin in the fourth quarter of 2013, with hiring expected to begin in early 2015 and commercial operations of the South Louisiana Methanol facility to start in mid-2016.

http://www.greencarcongress.com/2013/03/slm-20130301.htm

Canada approves 25-year export license for LNG Canada JV

The government of Canada has approved a long-term export licence to LNG Canada Development Inc. to export liquefied natural gas from the terminal proposed by the Shell consortium in Kitimat, British Columbia. LNG Canada is a joint venture comprising Shell, Korea Gas Corp., Mitsubishi Corp. and PetroChina International.

Currently, all of Canada's natural gas exports are to the United States. The government said that the approval of the licence demonstrates the momentum of Canada's burgeoning liquefied natural gas industry and the efforts underway to access growing world markets. Global energy demand is expected to increase by 35% between 2010 and 2035.

The LNG Canada licence is the third long-term licence issued since 2011. This 25-year licence allows for up to 24 million tonnes of LNG to be exported per year, making it the largest licence awarded to date. If this project and the four other proposed LNG projects for BC go forward, they could generate more than $1 trillion in economic activity over the next 30 years, according to the government.

Shell and our partners in LNG Canada-KOGAS, Mitsubishi, and PetroChina-are very pleased about today's announcement. We also recognize this important milestone is just one of the major regulatory approvals that will be required to make the project a reality, including a comprehensive environmental assessment. We will continue to work closely with First Nations, local communities, and the federal and provincial governments to meet social and environmental expectations.

-Anders Ekvall, Shell's Vice-President of LNG Americas

http://www.greencarcongress.com/2013/02/lngcan-20130226.htm