Dr. Mark Edwards, an Arizona State University professor, author, and well known “algaevangelist,” whose work focuses on resolving world hunger and pursuing sustainable energy with green solutions said, “There are those of us who believe Arizona will be the algae state. I’m just delighted.” Edwards is also AlgaeBio’s V-P of Corporate Development and Marketing.

Two bills were introduced by Rep. Matt Heinz (D-Tucson) back in January. The first algae-friendly bill, HB 2226, widens the tax definitions of agricultural real property in Arizona to include lands devoted to “algaculture”, offering the same lower property tax rates enjoyed by other farming businesses.

The second, HB 2225, will add the growth and harvest of algae to the definition of agricultural state trust lands, allowing the Arizona State Land Department to issue agricultural leases for algaculture operations.
Edward’s enthusiasm shows with, “It’s great to see such timely legislation that makes so much sense, and fits so well for this state — because of our non-arable land, flat land, the abundance of waste water and brine water, and 360 days of sunshine a year. Arizona has an opportunity to lead, globally, because a lot of other jurisdictions, other countries, will follow this example.”

The new state legislation is expected to allow Arizona to build a more appealing business climate for algae companies seeking affordable land to grow and harvest algae. It will also allow the people of Arizona to capitalize on the current business climate in the algae industry, which is seeing more and more ventures, whether they’re focused on biofuels, nutriceuticals, pharmaceuticals, or animal feed and move from the lab to the boardroom, backed by serious investment.

Admittedly Arizona is on an inside track with location, backing it up now with fair treatment for tax purposes and from Dr. Edwards a load of common sense. “I and others have been lobbying for something like this for almost three years now. Whether the water is running around a raceway, or bubbling in a vertical column, this is in fact agriculture — we’re farming in water,” says Dr. Edwards.

“This legislation, really, is an enabler. It makes algae production in Arizona more business-friendly. It will also help farmers engage in the algae industry, because they’re going to start thinking about using algae to remediate their manure and their waste streams,” Edwards adds.

Here’s the ‘killshot’ that other states are going to have to come to grip with and top for competitiveness in locating facilities and the jobs:

Edwards continues, “And remember, growing is only one part of it. Much of the tax comes from finished products. If we can invest in our future, with more product going into the supply chain, retail sales will make up for the lower taxes many, many times over. The consumers benefit. The taxpayers benefit. It’ll all come back around, big-time. And that was really the argument that got (the legislation) through.”

Florida is in part, listening. New energy legislation in the state of Florida became law April 14 despite Florida Gov. Rick Scott’s failure to sign the bill. The legislation, HB 7117, contains several measures aimed to encourage the development and expansion of the renewable energy sector within the state, including biofuels production and distribution. The bill also addresses policies and restrictions for growing certain strains of algae and cyanobacteria.

While Ohio and Arizona are getting competitive for business growth, Florida is fumbling with limits on an odd assortment of sales tax exemptions, for some unimaginable reason. There is also an investment tax credit related to biofuels production. Under the bill, the credit can apply to up to 75 percent of all capital costs, operation and maintenance costs, and research and development costs that are incurred between July 1, 2012, and June 30, 2016. The credit cannot exceed $1 million per fiscal year for each taxpayer. A limit of $10 million is made per fiscal year for all taxpayers – how’s that for not looking, well, serious.

The Florida law includes provisions related to the cultivation of some algae species. Under the new law a person may not cultivate a nonnative plant, algae, or blue-green algae – including genetically engineered plants, algae and blue-green algae in plantings greater in size than two contiguous acres, except under a special permit.

Florida has dived right into the Orwellian or big brother knows better for you mentality with a permit is not required to cultivate plants that, based on experience or research data, do not pose the risk of becoming an invasive species. Plants commonly grown in the state for the purpose of human food, commercial feed, feedstock, or forage are not covered by the provision. Additional exemptions could be made to the permitting requirements based on consultations with the Institute of Food and Agricultural Sciences at the University of Florida. A bureaucratic barrier is now fully set up.

Ohio and Arizona are in the hunt for algae producers, with Florida nibbling at the idea. Perhaps a boom of activity will spark other states and load a little sense into Florida. Its happening, and those are the states on the front line.

The novel form of catalytic nickel-molybdenum-nitride is described in a paper published online May 8, 2012 in the journal Angewandte Chemie, International Edition.

Hydrogen gas offers one of the most promising sustainable fuel alternatives. But traditional methods of producing pure hydrogen face significant challenges in unlocking its full potential, either by releasing carbon dioxide when its sourced from natural gas or requiring rare and expensive chemical elements such as platinum hwne sourced from water by electrolysis.

The new electro catalyst surprised the scientists with its high-performing nanosheet structure, introducing a new model for effective hydrogen catalysis.

Brookhaven's Nickel Molybdenum Nitride Catalyst for Splitting Water

Brookhaven Lab chemist Kotaro Sasaki, who first conceived the idea for this research explains, “We wanted to design an optimal catalyst with high activity and low costs that could generate hydrogen as a high-density, clean energy source. We discovered this exciting compound that actually outperformed our expectations.”

Background – Water provides an ideal source of pure hydrogen its abundant and free of harmful CO2 gas byproducts. The electrolysis of water, or splitting water (H2O) into oxygen (O2) and hydrogen (H2), requires electric current and an efficient catalyst to break chemical bonds while shifting around the protons and electrons. To justify the effort, the amount of energy put into the reaction must be as small as possible while still exceeding the minimum required by thermodynamics, a figure associated with what is called ‘overpotential’.

For a catalyst to facilitate an efficient reaction, it must combine high durability, high catalytic activity, and high surface area. The strength of an element’s bond to hydrogen determines its reaction level, if its too weak, and there’s no activity; too strong, and the initial activity poisons the catalyst.  Unfortunately, the strongest traditional candidate for electro catalytic activity, platinum, comes with a prohibitive price tag.

Platinum is the top material for electro catalysis, combining low overpotential with high activity for the chemical reactions during water-splitting. But with rapidly rising costs, already hovering around $50,000 per kilogram, platinum and other noble metals discourage widespread use
.
James Muckerman, the senior chemist who led the project takes up the explanation with, “People love platinum, but the limited global supply not only drives up price, but casts doubts on its long-term viability. There may not be enough of it to support a global hydrogen economy.”
The principal metals in the new compound developed by the Brookhaven team are both abundant and cheap: $20 per kilogram for nickel and $32 per kilogram for molybdenum – that’s 1000 times less expensive than platinum. But with energy sources, performance is often a more important consideration than price.

“We needed to create high, stable activity by combining one non-noble element that binds hydrogen too weakly with another that binds too strongly. The result becomes this well-balanced Goldilocks compound – just right.”  That simple explanation makes clear what the team managed to do.

In the new catalyst, nickel takes the reactive place of platinum, but it lacks a comparable electron density. The scientists needed to identify complementary elements to make nickel a viable substitute, and they introduced metallic molybdenum to enhance its reactivity. While effective, it still couldn’t match the performance levels of platinum.

Now research associate Wei-Fu Chen, the paper’s lead author takes up the explanation, “We needed to introduce another element to alter the electronic states of the nickel-molybdenum, and we knew that nitrogen had been used for bulk materials, or objects larger than one micrometer. But this was difficult for nanoscale materials, with dimensions measuring billionths of a meter.”

The scientists expected the applied nitrogen to modify the structure of the nickel-molybdenum, producing discrete, sphere-like nanoparticles. But they discovered something else.

Subjecting the compound to a high-temperature ammonia environment infused the nickel-molybdenum with nitrogen, but it also transformed the particles into unexpected two-dimensional nanosheets. The nanosheet structures offer highly accessible reactive sites and more reaction potential.

Using a high-resolution transmission microscope in Brookhaven Lab’s Condensed Matter Physics and Materials Science Department, as well as x-ray probes at the National Synchrotron Light Source, the scientists determined the material’s 2D structure and probed its local electronic configurations.

“Despite the fact that metal nitrides have been extensively used, this is the first example of one forming a nanosheet,” Chen said. “Nitrogen made a huge difference – it expanded the lattice of nickel-molybdenum, increased its electron density, made an electronic structure approaching that of noble metals, and prevented corrosion.”

The new Brookhaven catalyst performs nearly as well as platinum, achieving electro catalytic activity and stability unmatched by any other non-noble metal compounds. “The production process is both simple and scalable,” Muckerman said, “making nickel-molybdenum-nitride appropriate for wide industrial applications.”

While this catalyst does not represent a complete solution to the challenge of creating affordable hydrogen gas, it does offer a major reduction in the cost of essential equipment. The team emphasized that the breakthrough emerged through fundamental exploration, which allowed for the surprising discovery of the nanosheet structure.

This is really good news.  Currently most industrial hydrogen is sourced from natural gas so coming up with a competitive water based source is quite useful.  Even as natural gas is at a very low price, the hydrogen needed could grow if the price could be driven furthr down.

For many experimenters aluminum has been the electro catalyst of choice.  Getting the new Brookhaven material out into the hands of the thousands of experimenters making Browns Gas.  The new material could be a step into much more and more efficient hydrogen use.

Natural gas prices range from $1.49 to $2.59 in Colorado, Wyoming and Utah.  This is far less than gasoline.

Honda builds a Civic Compressed Natural Gas (CNG) sedan and has been selling a few of these natural gas vehicles in select markets for years.

At $4.00 gasoline the natural gas equivalent is running $2.50 in the higher priced markets.  That was back in May of 2011 when Mark Koebrich at Denver’s 9NEWS interviewed David Padgett, a Honda CNG owner.

Padgett said, “It’s costing me one-third of the cost of commuting with gasoline as it does to commute with natural gas. I wouldn’t drive anything else. If I was buying gasoline, it would have cost me over $30 to fill up this car. The actual cost of the natural gas was about $12, and if I do it in my garage, it’s going to be about $4.”

Another lure is you can install a natural gas hook-up at home in the garage from your utility gas line. You pull the hose from the wall and refuel at home for a fraction of the commercial station price. It’s almost that simple.

Padgett concludes, “You’ll burn natural gas when you can, and if you need to back it up with gasoline, it’s there for you as well. Same engine – no difference.”

Ford Super Duty Available with Compressed Natural Gas Fueling

The catch is one needs two fuel tanks.  Not something you add on at home.  But the manufacturers are catching on.  Ford’s CNG trucks have been available since 2009. Dual-fuel sedans are expected to follow in the 2013 model year. GM is offering two pickup models and a dual-fuel Ram Heavy Duty truck production model of the Dodge Ram has a load-bearing compressed natural gas tank immediately behind the cab with the normal gas tank in the usual place.

That’s the US Big Three Automakers plus Honda.  OK – two cars builders and three pickup truck makers is a major start.

But the big opportunity is application to large trucks.  Trucks have the room and the capacity to carry two fuel loads.  Various plans are popping up to line the interstate system with CNG filling stations. For diesels adding CNG injection is more complex, but the fuel cost savings would quickly recover the investment when a truck is traveling over one hundred thousand miles a year.

Once a part or combination of the plans gets underway the rest of use could seriously look for natural gas duel fuel vehicles.  With some careful planning a home served with natural gas may justify the piping and compressing for home filing.

Many pundits believe CNG technology will catch on over the next few years, just as hybrids are beginning to now. Toyota Motor Sales more than doubled hybrid sales in April (compared to last year), on the heels of over 50,000 hybrids of all makes selling in March.

There is less doubt about the supply of natural gas than the gasoline and diesel supply and assuming the government stays out of the way that should last for years, perhaps decades. If the methane hydrates supply of natural gas can be tapped cheaply the supply would last tens of centuries.

The flex fuel option has been a smart choice for years, hybrids the cost conscious choice more recently and CNG looks to be the next big thing.

On the other hand, pretty soon ‘dual fuel’ might be redundant – just make CNG cars and call it done could come pretty quickly with a price advantage driving the switch.

Chevron's Pacific Santa Ana Drillship. Click image for the largest view.

Able to work in 2 1/3rd miles deep water and over seven miles into the earth the new ship is a world leader.  Named the Pacific Santa Ana the ship was built to Chevron’s specifications under a five-year contract with a subsidiary of Pacific Drilling S.A.  She’s headed for the Gulf of Mexico.  After additional equipment is installed and tested, Pacific Santa Ana will be used for exploratory and development drilling in the deepwater of the gulf.

Deepwater Drlling Prewssures With and Without Dual Gradient Design. Click image for the largest view.

Dual Gradient Drilling (DGD) employs two weights of drilling fluid (link to a Chevron presentation pf file).  Conventional drilling on land and at sea uses a single drilling fluid weighted with additives in the borehole.  DGD uses two weights of drilling fluid – one above the seabed, another below. This allows drillers to more closely match the pressures presented by nature and effectively eliminates water depth as a consideration in well design. DGD also allows drillers to more quickly detect and appropriately react to downhole pressure changes, which can enhance the safety and efficiency of deepwater drilling operations.

Deepwater wells in the Gulf of Mexico and other parts of the world including West Africa and the Caspian Sea are challenging due to the narrow pore pressure/fracture gradient environment. The DGD system gives operators a tool to manage the downhole environment while drilling, resulting in longer casing strings and/or larger diameter completions. The DGD system increases drilling efficiency while lowering mechanical risk and well costs.

The Pacific Santa Ana is equipped with a DGD riser, a mud-lift pump handling system, six mud pumps – three for drilling fluid and three for seawater – extensive fluid management system enhancements and more than 72,000 feet of DGD-related cables.

Chevron's new GE Built Mud Lift Pump. Click image for the largest view.

A key element of the system is the MaxLift 1800 mud-lift pump from GE. To achieve a dual gradient, flow from a well being drilled is diverted to the MaxLift 1800 pump, which is located above the blow out preventer and pumps the cuttings-laden mud back to the drilling vessel in an auxiliary line.

The riser is then filled with seawater density fluid, so the reservoir “feels” as if the rig is located on the seabed (that means essentially that the pressures are neutral at the seafloor taking out the pressure that causes a blowout to flow oil out to the environment) since the MaxLift pumps prevent the hydrostatic pressure of the mud from being transmitted back to the wellbore. The new GE pump can deliver up to 1,800 gpm at discharge pressures up to 6,600 psi and can handle solids up to 1.5 inches in diameter.

The consultation firm Stress Engineering Services report for the US Bureau of Ocean Energy Management, Regulation, and Enforcement in 2011 (a pdf download) explored the risk profile of DGD, noted that DGD is a variation and a subset of Managed Pressure Drilling (MPD), which is a drilling tool that is intended to resolve chronic drilling problems including well stability and well control incidents.  MPD is intended to mitigate the risks and costs associated with drilling wells that have narrow downhole environmental limits by proactively managing the annular hydraulic pressure profile.

In the executive summary of the Stress Engineering Services report the firm points out, “Prior to April 20, 2010 (the date of the BP Deepwater Horizon explosion), the question of a catastrophic event was not a matter of “if”, but “when”. Drilling operations in a deepwater environment is an expensive endeavor. It is expensive for a number of reasons, but the chief reasons are to protect human life, equipment, and the wellbore in a very inhospitable environment. In a single pressure gradient environment (conventional drilling), it is easy to depart from the drilling window because of the narrow drilling window between the pore pressure and the formation fracture pressure. The Dual Gradient Drilling System re-establishes a margin of safety not obtainable in a single gradient system. Even the popular variant of Managed Pressure Drilling called Constant Bottomhole Pressure falls short of providing all of the well control benefits associated with DGD.”

“The most impressive aspect of Dual Gradient Drilling is that it is as safe or safer than current conventional drilling techniques AND provides for full riser margin, where the well is fully controlled in the event of riser disconnect AND problem wells can be drilled and completed instead of abandoned either with cement plugs or in a file labeled “TOO RISKY TO DRILL – TECHNOLOGY NOT AVAILABLE”.”

“…While there are risks associated with any drilling operation, deepwater well control is enhanced with DGD. Environmental episodes are also minimized. In the event of an emergency disconnect from the wellhead, seawater or a similarly compatible fluid dissipates into the surrounding water AND the well is under control because the hole is full of properly weighted drilling mud. DGD is like having a rig on the seabed floor. The riser margin is intact. It does not matter if the water depth is 5,000 feet or 15,000 feet, should the riser become disconnected, the well will be dead.”

One has to give Chevron credit for raw courage, something not seen in big corporate environments.  Its likely the commitment for the building of the Pacific Santa Ana predated the BP Deepwater Horizon event, still Chevron has pressed on and is still pressing on in the face of a government playing shiftlessly on permits and permissions going so far as to deny pipeline applications.  One cannot say with any honesty that the industry has held back on investing in producing oil.

Now, to rephrase the words of Stress Engineering, TECHNOLOGY IS AVAILABLE.  Chevron is first with the Pacific Santa Ana and there are more ships readied to drill more wells even deeper.

Farnesene is a 15-carbon isoprenoid hydrocarbon molecule that works as the basis for a wide range of products as varied from specialty chemical applications to transportation fuels such as diesel. When used as a fuel precursor, farnesene can be hydrogenated to farnesane, which has a high cetane number of 58.

Amyris Pilot Scale Fermentation Suite

Amyris is presenting a summary of the results at the 34th Symposium on Biotechnology for Fuels and Chemicals in New Orleans, Louisiana.  The project comes from a U.S. Department of Energy funded renewable diesel effort.

Sweet Sorghum in Cultivation. Click image for the largest view.

The pilot-scale project uses both the free soluble sugars and the cellulosic biomass sugars from Ceres’ sweet sorghum hybrids grown in Alabama, Florida, Hawaii, Louisiana and Tennessee. To process the soluble sugars that accumulate in the plants, the sorghum juice was first extracted from the stems and concentrated into sugar syrup by Ceres. Then Amyris then processed the syrup at its California pilot facility using its proprietary yeast fermentation system that converts plant sugars into its trademarked product, Biofene.

The DOE’s National Renewable Energy Laboratory (NREL) converted the leftover biomass from Ceres’ hybrids into cellulosic sugars at its Colorado pilot-scale biochemical conversion facility, which Amyris subsequently fermented into renewable farnesene.  That put almost the entire plant into the fuel precursor.

Secondary products from the Amyris biorefinery project include lubricants, polymers and other petrochemical substitutes. These secondary products are derived from the same C15 farnesene fermentation intermediate as the Amyris Renewable Diesel, providing opportunities to reduce risk in commercial production.

Spencer Swayze, Ceres director of business development said, “We believe that sweet sorghum could be an important and complementary source of fermentable sugars as the U.S. expands the production of renewable biofuels and biochemicals through the use of non-food crops outside of prime cropland. As an energy crop, sweet sorghum is an impressive producer of low-cost, fermentable sugars. A second stream of sugars from the biomass would be highly compelling.”

Sweet sorghum as a dedicated energy crop has a number of advantages. Its fast growing and can efficiently produce both large amounts of fermentable sugars and biomass. The plants require substantially less fertilizer than sugarcane, and can be grown in drier areas because it utilizes water more efficiently.

Todd Pray, Amyris director of product management said, “The results from these evaluations confirmed that the Amyris No Compromise renewable diesel production process performs well across different sugar sources. Ceres’ sweet sorghum hybrids produced sugars that yielded comparable levels of farnesene as sugarcane and other sugar sources Amyris has utilized. Sweet sorghum can provide timely feedstock flexibility with environmental benefits. We look forward to utilizing Ceres’ sweet sorghum in our commercial-scale production facilities.”

Amyris Sweet Sorghum to Diesel Process Diagram. Click image for the largest view.

The primary product of the Amyris IBR is Amyris Renewable Diesel, an advanced biofuel registered for use by the US EPA and covered by an issued US patent.

This news is likely a serious step into building a middle distillate range of bio hydrocarbons.  Amyris is already working with Total in Brazil working on a 50:50 joint venture company that will have exclusive rights to produce and market renewable diesel and jet fuel worldwide, as well as non-exclusive rights to other renewable products such as drilling fluids, solvents, polymers and specific bio-lubricants. The venture aims to begin operations in the first quarter of 2012.

As for the numbers, which seem to be proprietary, Amyris is scaling up its Biofene production in Brazil, Europe and the United States through various production arrangements with six known to be in hand.  Going for the investment at scale indicates that something commercial is worth putting in significant money.

The Ceres feedstock could bring mass production.  What the production rates are hasn’t been disclosed yet.  But as commercial scale efforts get further underway and efforts to acquire land and farming skill commitments – the values are sure to leak out.  How sweet sorghum compares to cotton, peanuts, corn and soybeans is yet to be seen.  To be competitive the prices have to support the production switch for terms long enough for the investments to payback and profit producers.

With a great cetane number and no sulfur the diesel product would be very desirable.

One would expect that a built molecule such as Amyris makes for a middle distillate would be more costly than a derived one coming from crushed seed oils and other sources. Time will tell, and the energy rich compression ignition engine will live on.

As Al Fin pointed out yesterday natural gas is priced to a barrel of oil equivalent at about $10-$11 per the estimable Geoffrey Styles view, something less than 10% of the cost of oil.  For North Americans adding a viable and hopefully low cost means to make use of gas hydrates could be giant boost to low cost fuel sources and a massive kick to the economy.

For experts the methane hydrates resource is the largest reserve of hydrocarbons in the planetary crust. So far humanity has not devised a process to economically harvest this immense energy wealth. Today’s DOE announcement may point the way to a new era in abundant energy to build out a bigger and better world economy.

By injecting a mixture of carbon dioxide and nitrogen into a methane hydrate formation (pdf link) on Alaska’s North Slope, the DOE partnering with ConocoPhillips and Japan Oil, Gas and Metals National Corp was able to produce a steady flow of natural gas in the first field test of the new method. The test was done from mid-February to about mid-April this year.

Methane Hydrate Test Site Map of US DOE, CononcoPhillips and JOGMNC Process Test. Click image for more info.

The department said it would likely be years before production of methane hydrates becomes economically viable. Secretary Chu said in his statement,  “While this is just the beginning, this research could potentially yield significant new supplies of natural gas.”

Methane hydrates are cold ice crystal-like structures that contain methane the chemical of natural gas. The hydrates are located under the Arctic permafrost and in ocean sediments along the continental shelf and widely spread worldwide.

Methane Hydrate Resources per Der Spiegel. Click image for the largest view.

Gerald Holder, dean of the engineering program at University of Pittsburgh, who has worked with the DOE’s National Energy Technology Laboratory on the hydrate issue, said before the announcement he had been skeptical about what researchers would be able to accomplish.

He said the main problem until now was finding a way to extract natural gas from solid hydrates without adding a whole lot of steps that made the process too expensive, which makes the success of this new test significant.

“It makes the possibility of recovering methane from hydrates much more likely. It’s a long way off, but this could have huge impact on availability of natural gas,” said Holder.

While everyone is suggesting that methane hydrate production is some time in the future, we might note that a partner is from Japan, a country that has been buying via imports virtually all its energy and fuel inputs.  A glance at the map of potential reserves shows that Japan may well pour on the intellectual and financial power to get results much quicker than many expect.

On the other hand, for North Americans natural gas is ratcheting down to dirt cheap, with more resources with the new horizontal drilling and reserve fracturing available on land and significant amounts of natural gas at sea in already developed areas.

For everyone the matter of coming up with the CO2 for the injection is going to be a significant issue.  First just gathering it remains a significant problem.  Making it from – natural gas – is the preferred method today.  That raises the question if the CO2 injected is lost to sequestration or is it recycled for reuse, or what proportion is being lost or recycled?  CO2 is very useful and it may become a valuable resource in its own right very soon.

Abundance makes a lot of things that weren’t viable at a price possible at lower costs.  Abundant fission or cold fusion could make electrolysis viable freeing hydrogen for adding to coal for both liquid fuels and CO2 sources.  Scaling could make such concepts usual and common thinking very quickly.

For now though the DOE and partner’s news is very gratifying.  It must be giving the futurists at OPEC an OMG moment, again.  Things are going to be changing.

Lets hope the DOE and the partners spill some more info soon so we can have a better look.

Octane numbers measure in scale the ability of a fuel to resist “knock” an ignition event resulting from premature fuel burning in spark-ignited engines.  The early ignition drives the piston back down the cylinder the wrong direction, which can cause engine damage when the “knock” is severe or prolonged.

Higher octane ratings in fuel blends would enable greater thermal efficiency in future engines through higher compression ratios and/or more aggressive turbocharging and downsizing of current engines on the road today through more aggressive spark timing under some driving conditions.

Ethanol's Impact on RON Octane Ratings in Gasoline. Click image for the largest view.

Ethanol and methanol offer higher research octane numbers (RON) and motor octane numbers (MON) when compared to gasoline. The alcohols also have a greater latent heat of vaporization than gasoline, which contributes to their higher RON values and provides additional charge cooling in direct-injection (DI) engines.  That means when the alcohols are sprayed into the engine’s induction air the charge of air is cooled more by the evaporation of the alcohol.

The two alcohols are not equal to gasoline.  Detractors focus on the lower energy density than gasoline, potentially higher or lower vapor pressures, altered distillation properties, and potential for water-induced phase separation.  These are all valid points – easily compensated for by proper engineering.

Today the situation is that ethanol is blended into a gasoline blendstocks formulated with a lower octane rating such that the net octane rating of the resulting final blend for sale is unchanged from historical levels.

Ford is making the case, with a hard scientific, peer reviewed, repeatable study what racing folks, hot rodders, engineers, and smart consumers with high compression engines have known for years.

The high octane rating of ethanol could be used in a mid-level ethanol blend to increase the minimum octane number (Research Octane Number, RON) of regular-grade gasoline.

Ford suggests that the societal benefit comes from automakers having an opportunity to improve their engines to a higher compression ratio.  The compression ratio is a comparison of the volume of the open cylinder to the cylinder volume when the piston has squeezed the cylinder to the smallest volume.  The same amount of fuel and air squeezed into a smaller space sets up a more energetic fuel burn that equals more mechanical energy out and less heat lost.
The Ford team used their already developed a linear molar octane blending model to quantify RON potential from ethanol and blendstock.  From the results the team estimated that an increase of 4-7 points in RON are possible by blending in an additional 10–20% by volume of ethanol above the 10% already present.

Here’s the opportunity Ford sees, keeping the blendstock RON at 88 (which provides E10 with a 92.5 RON), the estimated RON would be increased to 94.3 for E15 to as much as 98.6 for E30. The team further suggests RON increases may be achievable assuming changes to the blendstock RON and/or hydrocarbon composition.  An increase in blendstock RON from 88 to 92 would increase the RON of E10 from 92.5 to 95.6, and would provide higher RON with additional ethanol content (e.g., RON of 97.1 for E15 to 100.6 for E30).  This is high performance territory.

From the scenarios considered in the paper, the team estimated compression ratio increases to be on the order of 1–3 compression ration units for port fuel injection engines as well as for direct injection engines in which the greater evaporative cooling of ethanol can be fully utilized.

Ford is making a case that has been obvious to many for decades.  That has not stopped the detractors and the ill-informed followers from thinking up an assortment of ways to mislead consumers, the media and policy makers.  The facts the detractors have can prove up with low compression engine builds, poor maintenance, and skewing results.  There is also a strong motive.  The oil industry isn’t thrilled to lose 10% of the gasoline market to a competitor.

For everyone else, a higher compression ratio would be a good thing.  More efficiency, less fuel used and for the environmental types, less air would be cycled through engines.

What is, and as Ford points outs could be, the important issue is keeping the gasoline supply for sale with octane ratings high enough and priced so that higher levels of compression can be engineered into production vehicles at mass scale.

The point not being made was a significant point a couple decades ago when unleaded gasoline became the rule – lowering compression ratios.  It’s a waste of engineering, materials and air to mandate low octane ratings when the science and experience have proven otherwise for about one hundred years.

Perhaps Ford will be marking a turning point, getting the fuel market quality high enough to put efficiency with simple economy back into the automobile market.  It’s certainly been a long enough wait so far.

Researchers understand they must come up with a way to produce as much biofuel as possible in the smallest amount of space using the least amount of resources.  Water is of particular concern – most cultivated crops need fresh water while some algae can use various water sources ranging from wastewater to brackish water and be grown in small, intensive plots on denuded land.

Robert Settlage, Ph.D. at VBI’s Data Analysis Core (DAC) explains, “Getting the data is now the easy part. What we’re doing in the DAC is enabling researchers to move beyond informatics issues of assembly and analysis to regain their focus on the biological implications of their research.”

The payoff is further analysis revealed that with fairly straightforward genetic modification, N. gaditana should be capable of producing biofuel on an industrial scale, which may be the wave of the future in fuel research and production.

Nannochloropis Gaditana Content. Click image for the largest view.

Nannochloropis gaditana was selected because it comes from a strain family that’s attracted sustained interest from algal biofuels researchers owing to the high photoautotrophic biomass accumulation rates, high lipid content and the successful cultivation at large scale using natural sunlight in either open ponds or enclosed systems.  There is already a long company list in research such as Solix Biofuels, Aurora Algae, Seambiotic, Hairong Electric Company/Seambiotic and Proviron.

Improvements in strain productivity have been stalled by the lack of a genetically tractable model system.  That’s where VBI comes in.  Nannochloropis could out produce the popular green alga Chlamydomonas reinhardtii and the diatom Phaeodactylum tricornutum, both of which have genome sequences and established transformation methods, but neither of these algae is a natively exceptional producer of biomass or lipids.

Nannochloropis gaditana has been successfully cultivated outdoors at commercial scale, is oleaginous and stores relatively large amounts of lipid, in the form of triacylglycerides, even during logarithmic growth. N. gaditana has high photoautotrophic biomass and lipid production rates and can grow to high densities while tolerating a wide range of conditions with regards to pH, temperature and salinity.  These attributes make N. gadiyana a great candidate for development into a model organism for algal biofuel production.

The results have been published in Nature Communications.  Best of all the full paper is available to read and study.

It seems few people grasp the significance of the scale involved. Crude oil is being used at a rate in excess of 86 million barrels a day or 3,570,000.000 gallons.  U.S. ethanol is closing in on one million barrels per day or 42 million gallons. The ratio is 3,750:42 (About 536:6 or 89:1).

Biofuels have a long way to go.  The money is coming and the genome sequence for a top level candidate is in hand.  It won’t be long until a super algae design makes news.

Let the genetic designer modification begin.

The study paper is published today, March 30 2012, in the journal Science.  The study explains how James Liao, UCLA’s Ralph M. Parsons Foundation Chair in Chemical Engineering, and his team use a method for storing electrical energy as chemical energy in higher alcohols, which then can be used as liquid transportation fuels.

UCLA's Liao Electricity & CO2 to Make Butanol Fuel With Genetically Modified Organisms

Liao and his team genetically engineered a lithoautotrophic microorganism known as Ralstonia eutropha H16 to produce isobutanol and 3-methyl-1-butanol in an electro-bioreactor using carbon dioxide as the sole carbon source and electricity as the sole energy input.

For background, photosynthesis is the process of converting light energy to chemical energy and storing it in the bonds of sugar. There are two parts to photosynthesis, a light reaction and a dark reaction. The light reaction converts light energy to chemical energy and must take place in the light. The dark reaction, which converts CO2 to sugar, doesn’t directly need light to occur.

Liao explains, “We’ve been able to separate the light reaction from the dark reaction and instead of using biological photosynthesis, we are using solar panels to convert the sunlight to electrical energy, then to a chemical intermediate, and using that to power carbon dioxide fixation to produce the fuel. This method could be more efficient than the biological system.”

Continuing, Liao said that with biological systems, the plants in use require large areas of agricultural land. However, because Liao’s method does not require the light and dark reactions to take place together, solar panels, for example, can be built in the desert or on rooftops. It’s becoming obvious that any electrical source would do.

Theoretically, the hydrogen generated by solar electricity can drive CO2 conversion in lithoautotrophic microorganisms engineered to synthesize high-energy dense liquid fuels. But the low solubility, low mass-transfer rate and the safety issues surrounding free hydrogen gas limit the efficiency and scalability of such processes. Instead Liao’s team found formic acid to be a favorable substitute and efficient energy carrier.

Liao goes on, “Instead of using hydrogen, we use formic acid as the intermediary,” said Liao and then describes the process, ”We use electricity to generate formic acid and then use the formic acid to power the CO2 fixation in bacteria in the dark to produce isobutanol and higher alcohols.”

With the process worked out the team now believes the electrochemical formate production and the biological CO2 fixation and higher alcohol synthesis open up the possibility of electricity-driven bioconversion of CO2 to a variety of chemicals. In addition, the transformation of formate into liquid fuel will also play an important role in the biomass refinery process.

Liao winds up the press release saying, “We’ve demonstrated the principle, and now we think we can scale up. That’s our next step.”

Perhaps then the bedeviling questions can be answered.  How much electricity per unit of formic acid, how much formic acid and CO2 to what price of microorganisms, and what does a gallon cost?  The press release is very vague.

Yet one can fully understand the “Eurkea!” feeling and the rush to publish.  If the scale numbers work out well, the stampede to the researchers door will be quite something.

Liao points out an important point, “The current way to store electricity is with lithium ion batteries, in which the density is low, but when you store it in liquid fuel, the density could actually be very high. In addition, we have the potential to use electricity as transportation fuel without needing to change current infrastructure.”

This is an astonishing prospect.  The sources for CO2 are a long list.  Coal fired power plants alone generate an enormous store of CO2, relatively concentrated and not so hard to source. Using coal twice would an impressive accomplishment.  Displacing some oil production would be a bonus.  Depending on the state of the CO2 concentration crude oil could be a nearly obsolete product.

If the concentration required were low enough perhaps atmosphere alone would do as a source – an expectation quite hopeful, to say the least.

Liao has cracked into a huge potential opportunity.  How the first step numbers come in will be interesting, but when the process concept shows its details Liao and his team may be credited for an entire new industry.

This news makes an important point – for any nation with any sense, very low cost electricity is going to be an economy supporting bedrock and expensive electricity a millstone to dragging an economy down.

The folks at UCLA must be very proud today – as we are of them.

It’s also a boon to environmentalists.  For the ones still thinking about the world we live in and means to a better future keeping the crude oil off the roads and rails is a great relief.  While some extremists avidly look for a future freed of carbon based energy stores, the Plan B might come as a shock, but banking one’s dreams on the CO2 idea has always been doomed.

The trigger for the announcement yesterday was Enbridge Inc. and Enterprise Products Partners L.P. have secured pipeline capacity commitments from oil shippers.  There hasn’t been any doubt the oil could flow, the documents needed signed and on file to secure the financing and get underway with construction.

The various phases are going to go around both the political barrier of the President and the contentious Nebraska territory over the massive Ogallala Aquifer.  Nebraska had its arrangement over the aquifer for the Keystone worked out long ago, a fact the administration and major media simply didn’t care to see. The bad news is the jobs, construction and investment is getting moved 4 –500 miles away.  South Dakota, Nebraska and Kansas folks might see this as a betrayal, but the oil needs moved and no one needs crude oil in trucks and rail cars going hundreds of miles.

Enbridge Plan B for Crude Oil to the Gulf Coast. Click image for the largest view.

What is planned is a 512-mile, 30-inch diameter twin (a parallel line) along the route of the Seaway Pipeline from the big hub at Cushing Oklahoma to the Gulf Coast refining center, adding 450,000 bpd of capacity to the existing system (for a total 850,000 bpd).

Heading to the north via the northeast, Enbridge announced plans to proceed with an expansion of its Flanagan South Project. This pipeline is named as it starts from Flanagan, Illinois and goes to Cushing, Oklahoma.  The line will be upsized to a 36-inch diameter line with an initial capacity of 585,000 barrels per day (bpd). The Flanagan South Pipeline project will be constructed along the route of Enbridge’s existing Spearhead Pipeline connecting the Flanagan Terminal, southwest of Chicago, to Enbridge’s Cushing Terminal in Oklahoma.

On to the north the Flanagan Terminal connects to the Enbridge pipeline system reaching up to the Bakken Oil formation field of North Dakota and Canada, on to Edmonton and finally up to Fort McMurray in the center of the oil sands field.

Enbridge Plan B Route to the Gulf of Mexico. Click image for the largest view.

This means a lot more oil can get to the US refineries at the Gulf Coast by pipeline.  The refineries have been getting oil from pipelines to be sure, but the new pipeline capacities can displace some ocean going tanker traffic.

The new oil supplies are going to saturate the Gulf Coast refinery complex.  The pipeline firms announced construction of a new 85-mile 30-inch diameter pipeline that will be built from Enterprise’s ECHO crude oil terminal southeast of Houston to the Port Arthur/Beaumont, Texas refining center, which will give shippers access to heavy oil refineries on the Gulf Coast, too.

On the money angle the total estimated cost of the Flanagan South Pipeline project has increased from the original $1.9 billion to $2.8 billion.  In addition, Enbridge’s share of the cost of the Seaway Pipeline twin line and extension with TransCanada is expected to be approximately $1.0 billion.

Most of the major work is due to complete before mid 2014.  Its reasonable to expect interference from those special interests so entrancing the administration and stimulus for legal and bureaucratic activists.  But the barriers are not at the top of the political power structure.  The projects will very likely get done.

The consumer benefit will not be so good as the Keystone XL project could have been, but its still a badly needed win.  There will not be much reduction in eat and west coast gasoline prices, but there will be crude oil to supply the gasoline.  The North American Oil Industry will get to make some money in the world oil market as exporters of finished products.

This is good and very welcome news.