Petrobras, the Brazilian based petroleum firm is reported to have qualified and approved a new technology to convert natural gas to synthetic crude oil.  The Petrobras’ CENPES Research and Development Centre completed its trials of the CompactGTL unit prompting Nicholas Gay, chief executive of CompactGTL to say, “The [Petrobras] test program has produced some extremely positive results and has shown the plant can be robust, with the operational availability (the percent of time a unit would operate) expected of large scale commercial facilities. We can now progress our plans in conjunction with clients throughout the world to develop commercial scale modular gas to liquid plants.”

CompactGTL offers a modular GTL solution for a variety of natural gas to liquids conversion needs.  The modular design and the implicit lower investment cost suggest the vast resource of non-marketable natural gas could become sources of crude oil.  That allows a pressure free containment and no temperature input that could then bring the liquid and more energy dense syncrude resources to market.

CompactGTL technology features proprietary catalysts and reactor designs derived from plate and fin heat exchanger manufacturing techniques. Modular plant design, incorporating multiple reactors in parallel, provides a flexible, operable solution to accommodate gas feed variation and decline over the life of the oilfield.  The firm is suggesting reactors can be relocated.  No huge installation needs to be built.

At the heart of the process are two banks of modular reactor blocks. Using an advanced derivative of plate and fin heat exchanger technology, these reactors allow the precise control of heat and gas flow over proprietary metal-supported structured catalysts, located in a regular array of thousands of closely spaced channels.  It’s looking like a factory mass production plan instead of custom built installations.

The first stage CompactGTL reactor uses Steam Methane Reforming to convert natural gas into syngas, a mixture of carbon monoxide and hydrogen. The syngas is fed into the second reactor where it is converted via the Fischer-Tropsch (FT) process into synthetic crude oil, water and a ‘tail gas’ composed of hydrogen, carbon monoxide and light hydrocarbon gases.

At this first introductory point it looks as though the CompactGTL needs only the natural gas and water source as inputs with a start source for the heat.  As the graphic shows, the steam cycles and the FT reactor refuels the first reformer reactor.

A key engineering advantage is the close relationship between the two reactors providing efficient management of the overall system.  The two reactions are tuned to work together to maximize efficiency and minimize waste streams depending upon the specific application and location of the plant. The water produced in the Fischer-Tropsch reaction can be treated to remove impurities and recycled back into the steam reforming process.

CompactGTLs proprietary catalysts and the shared activities of the two reactors is planned to offer a self-contained plant operating a stable process that won’t need an oxygen supply.

Al Fin has pointed out that CompactGTL isn’t alone in the soon to explode market.  Mr. Fin also noted the Oxford Catalyst and the Velocys microchannel technology as candidates worthy of close watching. As those two firms reach milestones in their paths we’ll have a look.

To recap, natural gas is a wonderful fuel, but is doesn’t transport easily or cheaply over great distances.  Moving down pipelines with customers each few hundred feet works great.  Big resources can justify large investments in pipelines to get to a market.  But in much of the world and in remote or deep water locations the gas is just shut in, burned off for no use other than safety, or worst of all just vented into the atmosphere to the justified horror of the global warming folks.

Jeremy Coller, the investor behind the CompactGTL effort understands the impact a breakthrough on the investment needed to get natural gas to market said, “With this approval from Petrobras the company has passed a critical milestone, demonstrating its leadership in an area with the potential to be a game-changer for oil and gas exploration.”

Its looks like a game-changer, indeed.

Hydrates are a water ice and usually a natural gas compound that have been explored by researchers as a source of alternative fuel or storage medium for CO2.  The PNNL researchers note at first discovery the hydrogen storage value approaches the goal of a Department of Energy standard and could make hydrogen hydrates practical and affordable for storage.

Using computer analysis of the ice and gas compound reveals key details of its structure and researchers have accurately quantified the molecular-scale interactions between the gases of either hydrogen or methane, also known as natural gas – and the water molecules that the form cages around them.

The research team’s results from the Department of Energy’s Pacific Northwest National Laboratory were published in Chemical Physics Letters online December 22, 2011.

While hydrogen is the most interesting use of hydrates, PNNL chemist Sotiris Xantheas the lead author said, the results could also provide insight into the process of replacing methane with carbon dioxide in the naturally abundant “water-based reservoirs.”

Here’s the marvel revealed in the research as put by Xantheas, “Current thinking is that you need large amounts of energy to push the methane out, which destroys the scaffold in the process. But the computer modeling shows that there is an alternative low energy pathway. All you need to do is break a single hydrogen bond between water molecules forming the cage – the methane comes out, and then the hydrate reseals itself.”  This revelation has major implications on natural gas recovery.

Previously Xantheas and the colleagues used computer algorithms and models to examine the water-based, ice-like scaffold that holds the gas. Water molecules form individual cages made with 20 or 24 molecules. Multiple cages join together in large lattices. But those scaffolds were empty in the earlier analysis.

To find out how fuels can be accommodated inside the water cages, Xantheas and colleague Soohaeng Yoo Willow built computer models of the cages with either hydrogen gas – in which two hydrogen atoms are bound together – or methane gas, a small molecule made with one carbon and four hydrogen atoms.

In the hydrogen hydrates, the idea that could potentially be used as materials for hydrogen fuel storage, a small hollow cage made from 20 water molecules could hold up to a maximum of five hydrogen molecules and a larger cage made from 24 water molecules could hold up to seven.

The maximum storage capacity equates to about 10 weight-percent, or the percentage of hydrogen by mass in the chunks of ice.

However packing hydrogen in that tight puts undue strain on the system.  But it nearly doubles the DOE’s goal for hydrogen storage above a 5.5 weight-percent.

Now the story gets intuitive, innovative and just clever.  Experimentally, hydrogen storage researchers typically measure much less storage capacities. The computer model showed them why: The hydrogen molecules tended to leak out of the cages, reducing the amount of hydrogen that could be stored.

The PNNL team found that adding a methane molecule to the larger cages in the pure hydrogen hydrate prevented the hydrogen gas from leaking out. The computer model showed the researchers that they could store the hydrogen at high pressure and practical temperatures, and release it by reducing the pressure, which melts it.

Understanding how the gas interacts and moves through the cages can help chemists or engineers store gas and remove it at will.

Willow and Xantheas’ computer simulations showed that hydrogen molecules could migrate through the cages by passing between the figurative bars of the water cages. However there’s a problem to work out, the cages also had gates: Sometimes a low-energy bond between two water molecules broke, causing a water molecule to swing open and let the hydrogen molecule drift out. The “gate” closed right after the molecule passed through to reform the lattice.

With methane hydrates, some fuel producers want to remove the gas safely to use it.  So, Willow and Xantheas tested how methane could migrate through the cages.

The water cages are only big enough to comfortably hold one methane molecule, so the chemists stuffed two methane molecules inside and watched what happened. Quickly, one of the water molecules forming the cage swung open like a gate, allowing one methane molecule to escape. The gate then slammed shut as the remaining molecule scooted into the middle of the cage.

Xantheas explains, “This process is important because it can happen with natural gas. It shows how methane can move in the natural world. We hope this analysis will help with the technical issues that need to be addressed with gas hydrate research and development.”

The team’s work is still all in the computer, but the insight should allow a broad spectrum of researchers a blueprint for experimentation and the beginning steps of processes and engineering.  The best news is the storage rate is very high and the temperatures are in an easy to access zone with common refrigeration and low energy requirements to do the warm up.  The engineering challenge to today is substantial, but some very good minds are going to light up with this news.

A Northwestern University (NU) research team is hot on porous crystals called metal-organic frameworks, with their nanoscopic pores and incredibly high surface areas that are excellent materials for natural gas storage.  Metal–organic frameworks (MOFs) are porous materials constructed from modular molecular building blocks, typically metal clusters and organic linkers. These can, in principle, be assembled to form an almost unlimited number of MOFs, yet materials reported to date represent only a tiny fraction of the possible combinations.

Metal Organic Framework Sample Images. Click image for more info..

Metal-organic frameworks come in millions of different possible structures, so where does research zero in?

A (NU) research team has developed a computational method that can save scientists and engineers valuable time in the discovery process. Their new computer algorithm automatically generates and tests hypothetical metal-organic frameworks (MOFs), rapidly zeroing in on the most promising structures. These MOFs then can be synthesized and tested in the lab.

Using their new method the researchers quickly identified more than 300 different MOFs that are predicted to be better than any known material for methane (natural gas) storage. The researchers then synthesized one of the promising materials and found it beat the U.S. Department of Energy (DOE) natural gas storage target by 10 percent.

In addition to gas storage and vehicles that could burn natural gas, MOFs may lead to better drug-delivery, chemical sensors, carbon capture materials and catalysts. MOF candidates for these applications could be analyzed efficiently using the Northwestern method.

Team leader Randall Q. Snurr, professor of chemical and biological engineering in the McCormick School of Engineering and Applied Science explains the import of the research saying, “When our understanding of materials synthesis approaches the point where we are able to make almost any material, the question arises: Which materials should we synthesize?  This paper presents a powerful method for answering this question for metal-organic frameworks, a new class of highly versatile materials.”

The team’s study paper is “Large-Scale Screening of Hypothetical Metal-Organic Frameworks and was published by the journal Nature Chemistry. It also will appear as the cover story in the February print issue of the journal.

Graduate student in Snurr’s lab and first author of the paper Christopher E. Wilmer developed the new algorithm.  Omar K. Farha, research associate professor of chemistry in the Weinberg College of Arts and Sciences, and Joseph T. Hupp, professor of chemistry, led the synthesis efforts.

Wilmer takes the explanation of how the research affects the development of metal-organic frameworks, “Currently, researchers choose to create new materials based on their imagining how the atomic structures might look,” Wilmer said. “The algorithm greatly accelerates this process by carrying out such ‘thought experiments’ on supercomputers.”

The NU team was able to determine which of the millions of possible MOFs from a given library of 102 chemical building block components were the most promising candidates for natural-gas storage. In just 72 hours, the researchers generated more than 137,000 hypothetical MOF structures. This number is much larger than the total number of MOFs reported to date by all researchers combined (approximately 10,000 MOFs). The Northwestern team then winnowed that number down to the 300 most promising candidates for high-pressure, room-temperature methane storage.

The new computer algorithm combines the chemical “intuition” that chemists use to imagine novel MOFs with sophisticated molecular simulations to evaluate MOFs for their efficacy in different applications. The researchers say the algorithm could help remove the bottleneck in the discovery process.

The other people on the team are Michael Leaf, Chang Yeon Lee and Brad G. Hauser, all from NU.

13 million vehicles on the road worldwide today run on natural gas, including many buses in the U.S.  The number is expected to increase sharply due to recent discoveries of natural gas reserves with lower prices than gasoline.  Converting a vehicle to the fuel isn’t a major matter, albeit complex and includes a drop in available total power, as natural gas is lower than gasoline in energy density. Comparatively speaking, it’s a very cheap fuel.

Gas production in Pennsylvania increased to about 2.8 billion cubic feet a day in July 2011, up from about 0.6 billion cubic feet in January 2010, according to the U.S. Energy Information Administration.  This is no small matter for the Northeast’s supply for the 2011-12 winter heating season and industrial production.

Locally about 218,000 Pennsylvanians worked in Marcellus Shale-related industries at year-end 2010, helping drive the state’s unemployment rate below the national average.  The oil and gas industry’s beating on about energy jobs they could provide is ringing very true now that nearly a quarter million jobs are suddenly at risk.

The case is John E. and Mary Josephine Butler v. Charles Powers Estate et al filed in the Superior Court of Pennsylvania.  The Butlers are relying on previous rulings that established ownership of oil or gas doesn’t change hands unless it’s specified in a deed. In opposition the Powers’ heirs argue that the deed gave them the right to other minerals such as coal — and that they own the gas trapped in the shale the same way they would own the gas trapped in a coal seam.

For over a century Pennsylvania has required landowners to consider oil and gas rights separate from the more general and common “mineral rights” when transferring ownership of resources beneath the surface of their property.

The Powers argue shale gas is different and should be considered part of the mineral rights because it is contained inside rock.  It’s going to be a very hard sell that any hydrocarbon isn’t lodged in “rock” so to speak.

The Butlers leased the property about two years ago with a coalition of neighbors to Talisman Energy of Calgary who believes the lease is valid.

In the middle of all this is an 1881 deed for 244 acres in Pennsylvania’s Susquehanna County transferring “half the minerals and petroleum oils” under the land to Charles Powers.  The Butlers say they own all the gas because the deed transferring minerals to Powers’ heirs failed to specifically mention gas.

The key in this seems to be around the natural gas being a mineral or a petroleum product.  The Butler’s hope to keep gas in the petroleum definition and the Powers want the natural gas to be a mineral within a rock.

How this got this far is a question for Pennsylvanian property lawyers.

The Superior Court, the second-highest court in Pennsylvania ruled that current law doesn’t sufficiently address whether “Marcellus shale constitutes a mineral,” sending the question back to be hashed out by the lower court.

Meanwhile – oil and gas companies will face uncertainty about whether they’ve signed drilling leases with the right people – owners of oil and gas rights who signed leases with gas producers could find that they don’t own the gas after all – the oil and gas companies may need to check the title to thousands of oil and gas properties they’ve leased – lots of leases will have to be renegotiated.

Cases like these can take years to work their way through the court system.  Most worrisome for the long term is that Powers wins and sets off a revolution in oil and gas mineral rights.

If Pennsylvania is like most states in reporting legal proceedings the Bulters sued the Powers for all the money.

With the gas production at risk, the jobs at risk, more uncertainty in an already way overloaded economic uncertainty, a whole new set of expenses to clear up leases there’d be a lot of pressure on to get this resolved.

For a non-attorney looking at the reports is certainly seems to be a hot fight over a few words that say pretty clearly that half the mineral rights and petroleum’s oils would cover the Powers right to half the money.  If natural gas is one of the petroleum products and petroleum means oil the Powers are in.  Even if the revolution sets in and natural gas isn’t a petroleum product and is a mineral product the Powers still have half.  The court has to decide if the missing natural gas words are still inclusive from a document made in 1881.  Who would have thought that the nuisance of natural gas 1881 would be such a huge problem 130 years later.

Hopefully the folks in Pennsylvania will wake up and sort this out in short order. But don’t count on it.  There is a lot at stake there, right now.  That doesn’t mean the problem, which is a real one, will get the attention it deserves.

In 2007 Chemical engineers George Hirasaki and former graduate student Gaurav Bhatnagar at Rice University theorized that methane could be detected via transition zones 10 to 30 meters below the seafloor near continental shores.  At that level sulfate, a primary component of seawater and methane to react and consume each other.

What happens is as sulfate migrates deeper into the sediment below the seafloor, it decreases in concentration, as evidenced by measurements of the water (pore water) trapped between sediment particles from core samples. The depth at which the sulfate in the water gets completely consumed upon contact with methane rising from below is the sulfate-methane transition (SMT) zone.

In 2007 Bhatnagar argued in a paper the depth of this transition zone serves as a proxy for quantifying the amount of gas hydrates that lie beneath; the shallower the SMT, the more likely methane will be found in the form of hydrates in abundance at greater depth.

Sounds good. But . . .

The controversy that followed the publication of the original paper focused on sulfate consumption processes in shallow sediment and whether methane or organic carbon was responsible. Skeptics felt the basis of Bhatnagar’s model, which assumes methane is a dominant consumer of pore-water sulfate, was not typical at most sites. That sort of blew the idea as being truly representative.

Rice University chemical engineer George Hirasaki, left, and graduate student Sayantan Chatterjee. Click image for the largest view.

Sayantan Chatterjee, a fifth-year graduate student in Hirasaki’s lab, set out to prove the theory by bringing more chemical hitchhikers into the test matrix.  He added bicarbonate, calcium and carbon isotope profiles of bicarbonate and methane to the model.  Chatterjee says, “Those four additional components gave us a far more complete story.”  The paper was published this week by the Journal of Geophysical Research — Solid Earth

Hirasaki, who is Rice’s A.J. Hartsook Professor of Chemical and Biomolecular Engineering explains that including a host of additional reactions in their calculations on core samples, “can give a much stronger argument to say that methane flux from below is responsible for the SMT. The big picture gives more evidence of what’s happening, and it weighs toward the methane/sulfate reaction and not the particulate organic carbon.”

The Rice team sees two audiences for the research and the results that could be generated.  The first is the natural gas industry and its customers eyeing an energy resource. The second is the global warming crowd who see methane as the mother of all greenhouse gases.   That makes two diametrically opposed views eager to find out what’s down there.

For now Chatterjee had the chance to discuss his results with his peers in July at the seventh International Conference on Gas Hydrates in Edinburgh, Scotland, where he presented a related paper that focused on the accumulation of hydrates in heterogeneous submarine sediment.  The conference paper was awarded a first prize at the prestigious Society of Petroleum Engineers’ Young Professionals meeting and placed second at the Gulf Coast Regional student paper competition.

The Rice group has embarked on an important job for the future.  Much to the relief of long range planners for natural gas usage it looks like the Rice technique is going to have a noteworthy effect on helping locate the easiest and least expensive methane hydrate deposits.  One suspects that the basic idea isn’t going to help out the global warming crowd all that much – not that they won’t try to twist it to their advantage.  The global warming worry depends on releasing methane from depths that when warmed will give up methane – not something the Rice team was targeting – they’re looking much deeper and for truly large deposits.

The Rice group’s work isn’t going to be a revolution, rather is a big step of evolution to getting sources spotted that can justify the research needed to learn how to extract the methane at minimal cost and the least amount of environmental disturbance.  Just narrowing down the possible sites to the most desirable is going to help.

Once the best prospects can be quantified the really developmental research can get under way. Its one thing to experiment – and quite another when there are known billions of dollars of profit for serving a market.

Marcellus Shale within the Appalachian Basin. Click image for the largest view.

Before looking into this, keep in mind we’re looking through the work of the USGS, a department of the federal government.  As others have noted elsewhere the reliability of these kinds of things isn’t very high, rather they serve as pretty good guides over time on the resource availability by quantity.  What’s to be seen in the report is there’s lots more geology data now, much more production experience, and a considerable extension of the infrastructure to deliver natural gas from the gas fields to consumers.

The latest USGS assessment is an estimate of continuous gas and natural gas liquid accumulations in the Middle Devonian Marcellus Shale of the Appalachian Basin. The estimate of undiscovered natural gas ranges from 43.0 trillion cubic feet, a 95% probability to 144.1 TCF, 5 percent probability.  The estimate of natural gas liquids such as propane or liquid petroleum gas, ranges from 1.6 billion barrels at 95% probability to 6.2 billion barrels at 5 percent probability.

The oil industry can be said to have been born in the Eastern U.S.  Drake’s famous well was drilled in western Pennsylvania and since the 1930s almost every well drilled through the Marcellus shale found noticeable quantities of natural gas. By 2004 engineers reflecting on the Marcellus shale concluded the formation was a potential reservoir rock, instead of just a regional source rock, meaning that the gas could be produced from it instead of just being a source for the gas.

Technological improvements, most notably horizontal drilling and hydraulic fracturing of the shale rocks resulted in commercially viable gas production and the rapid development of a major, new continuous natural gas and natural gas liquids boom in the Appalachian Basin, the oldest producing petroleum province in the U.S.

Keep in mind, there’s no conventional oil type petroleum resources assessed in the Marcellus Shale of the Appalachian Basin.

The USGS bases its new update in undiscovered, technically recoverable resource due to new geologic information and engineering data, with significant technological developments in producing unconventional resources in the last decade.

The USGS qualifies the assessed estimates for technically recoverable oil and gas resources meaning those quantities of oil and gas producible using currently available technology and industry practices.  No adjustment or projection is included regarding economic or accessibility considerations. So the estimates include resources beneath both onshore and offshore areas (such as under Lake Erie) and beneath areas where accessibility may be limited by policy and regulations imposed by land managers and regulatory agencies. That’s a fair warning to consumers and industry that they’re on their own for keeping reserves available in the face of opposition from both those well justified and those frivolous and emotionally driven.

The USGS is the only provider of publicly available estimates of undiscovered technically recoverable oil and gas resources of onshore lands and offshore state waters. In this assessment the USGS worked with the Pennsylvania Geological Survey, the West Virginia Geological and Economic Survey, the Ohio Geological Survey, and representatives from the oil and gas industry and academia to develop an improved geologic understanding of the Marcellus Shale. The USGS Marcellus Shale assessment was undertaken as part of a nationwide project assessing domestic petroleum basins using standardized methodology and protocol.  Applied nationwide the new technique should firm up realistic expectations.

The other side is those states; Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia are going to see a new economic foundation built into their economies – a very welcome event – if they can keep political control and the exploration and development going.

There will be a lot of jobs, wealth and investment made in these states – if they can keep the anti energy lobbies from wrecking their future.  Keep it going and the next assessment may very likely increase the reserve estimate again.

A leader in a still quiet, but well funded and ambitious project is Jesse Ausubel of Rockefeller University (Of fame from his theory that the fuel economy will move from a highly carbon base to a more hydrogen enriched base). As Mr. Styles notes, “Although much is known about the behavior of carbon in the first seven miles or so of the earth’s crust into which we routinely mine and drill for resources, relatively little is known about the flows of carbon-based compounds in the other 99.6% of earth’s total volume.”  That’s a bit of a reality check – only 0.4% of the earth’s crust has over 150 years yielded nearly 2 trillion barrels of oil and equivalents with very likely 2 to 3 and maybe 4 times that much more to come with the technology of today.

A Slice of Earth Showing the Layers and Zones. This is the largest view.

In the west the experts conclude that remains of plant growth has been processed into their present petroleum form by exposure to high pressures and temperatures over the course of millions of years to make the recoverable oil and gas of today.  It seems completely plausible and the hard evidence can be seen in the coal seems readily dug up and examined, and put to use.  The western view seems concrete and is – as far as it goes.

That begs the questions of Mr. Ausubel and the his involvement with the Deep Carbon Observatory, an international project of the Carnegie Institution to investigate the organic and inorganic carbon cycles deep in the earth.  Here the effort is to ascertain what carbon exists even deeper that the top of the crust exploration has picked at for 150 years.  As there is quite a lot of carbon working at the surface now, what might be of use from deeper in the crust?

The premise could be, especially for the thinkers in the east, Russia as a prime example, that hydrocarbon deposits could exist in that they were formed by chemical or biological activity much deeper in the earth (a pdf link), and then migrated long distances before being trapped. If that premise were even correct in part, that would mean that not only some of these fuels are not truly fossil in origin – and thus essentially static and finite – but that they might actually be continuously regenerated by natural processes in much shorter time spans than millions of years.

Here in the west the parallel to the Russian concept was best described by an idea developed by the Cornell University physicist Thomas Gold, who believed that oil and gas are produced by deep-earth microbes feeding on natural sources of methane. From this it followed, Dr. Gold argued, that oil wells might be naturally replenished from vast sources of carbon deep in the planet. Dr. Gold’s theories also have far-reaching implications for the origins of life on earth.

The puzzle for this writer is the notion that one or the other of the ideas is correct suggesting the other is wrong.  Reality offers that both can be correct.

We do know the deep earth crust is populated by microbes that lead a largely independent existence from those on the surface. This dark world, flourishing but largely unknown, could have been the origin of life on earth and may influence it in many other ways.  Add in the fact that the carbon on earth got here from a star going super nova billions of years ago.  Keep in mind carbon is a lightweight element and is going to float up out of the mantle and core.  These facts plus carbons’ quite handy ability to react with and form new molecules and the constant recycling of the crust from continental subduction and subsequent volcanic eruption and mountain building refreshes and re exposes carbon at the surface.

Most all the carbon on earth is likely in the crust and atmosphere dispensed from diamonds to methane and CO2. Whether or not there are organisms sending up hydrocarbon molecules and the speed of such production may not be terribly significant.  But if a highly concentrated source is found a new rush to discover more would ensue.

Yet the carbon resource is all around us now.  One day the technology of a solar cell taking in the atmospheric CO2 and humidity in the air making methane and O2 ready for use in combustion back to CO2 and water will be invented.  That’s when there will be a seismic shift in market attention about carbon based fuel sources.

The difference between deep earth methane production and a methane solar cell is the time consumed to accomplish the reforming of the carbon.  It’s a tall order to comprehend the millions of years involved in the geologic carbon cycle but very easy to grasp a solar cell making methane ready to heat the home, fuel the car or feed a fuel cell.  To answer Mr. Style’s headlining question, “Are Oil and Gas Renewable” the answer is yes, of course, if you are patient enough.

A more thorough idea of what is going on way down deep is worth knowing.  As with all great explorations the payoffs may well be something entirely other than the point of the original interest.  Go! Mr. Ausubel, and please collect every possible data point along the way.

Algeria, already a major exporter of oil and natural gas is sitting on huge undeveloped reserves of shale gas that the country now intends to develop with the help of international partners. The estimate is that Algeria could come up with 1,000 trillion cubic feet of natural gas trapped in shale rock only 3,280 feet below the surface.

The drilling and fracturing transformation that started decades ago in the United States has companies and countries across the globe scrambling to replicate the success and develop shale gas reserves of their own.

Here is graphical list of the very biggest reserves within the borders of the short list of countries.  With the U.S thought to be set for decades if not centuries, the countries with higher reserves represent a huge resource.

Top 2010 World National Natural Gas Reserves. Click image for the largest view.

When we last looked at natural gas the interest was on another technology to recover gas that was not economical due to the costs of cleaning up the other chemicals that come out with the natural gas.  It seems that there is another technology on its way to clean up natural gas at a much lower cost.

A team of Battelle researchers at the Department of Energy’s Pacific Northwest National Laboratory has discovered a method that could dramatically cut the amount of heat needed during natural gas processing, reducing the amount of energy needed during a key-processing step.  The first blush is a savings of 10%.  That might turn out to be low.

Even now some raw natural gas is purified in a process called “sweetening” before it can be used as a fuel. The gas industry currently uses a process called Thermal Swing Regeneration for sweetening natural gas. In that process, chemical sponges called ‘sorbents’ remove toxic and flammable gases, such as rotten-egg smelling hydrogen sulfide from natural gas.

The chemical sorbents are dissolved in water with the gas set up to flow through. Then solution must then be heated up and boiled to remove the hydrogen sulfide, in order to prepare the sorbent for recycled future use. Once the hydrogen sulfide is boiled off, the sorbent is then cooled and ready for use again. This repeated heating and cooling requires a lot of energy and reduces the efficiency of the process.

The new, Battelle-PNNL created process is called Antisolvent Swing Regeneration, that takes advantage of hydrogen sulfide’s ability to dissolve better in some liquids than others at room temperatures. In the new process, the hydrogen sulfide “swings” between different liquids during the processing at nearly room temperature, resulting in its removal, in just a few steps, from the liquids that can be recycled again and again.

Phillip Koech, lead author and senior research scientist explains, “Because hydrogen sulfide is such a common contaminant in methane, natural gas processors could potentially use this method in the sweetening process, reducing their energy use and saving money on the cost of sorbent materials.”

In the lab the team dissolved hydrogen sulfide in several different recyclable binding organic liquids and found that nearly all of them could hold the chemical without added water. They found one – DMEA – that could hold the most hydrogen sulfide. A chemical analysis suggested that hydrogen sulfide forms a salt with DMEA, turning the DMEA from an oily liquid into something more like salty water, but not water at all.

Based on the chemical characteristics of the salty DMEA, the team thought the salt could be easily disrupted and turned back into the gas hydrogen sulfide by adding a liquid hydrocarbon called an alkane. They mixed the hydrogen sulfide-containing DMEA with the alkane known as hexane and shook it like a bottle of salad dressing. Most of the hydrogen sulfide returned to its gaseous nature and bubbled out of the mix, leaving a soup of DMEA and hexane.

Having successfully removed the hydrogen sulfide from the DMEA, the team needed to find an alkane that would separate out the hexane and the DMEA, and found one in hexadecane, which separates from DMEA in the same way that oil and vinegar drift apart in salad dressing. The team suspects the components separated due to a bit of salt remaining in the DMEA.

But unlike hexane’s ability to perform at room temperature, the team had to warm the DMEA-hexadecane solution just a little – to about 40º C (104º F), the temperature of a hot summer day or a hot tub – to get the liquids to release the hydrogen sulfide. After the gas bubbled off and the two liquids separated, the team could pour off the hexadecane and re-use the left over DMEA.

Lastly, the team tested how well the chemicals could be re-used by recycling the hydrogen sulfide through the DMEA and hexadecane five times. The liquids retained their ability to remove the hydrogen sulfide and recover the DMEA in its initial form. The team expects DMEA will be able to pull hydrogen sulfide from natural gas using this process and they expect to scale up the process with future research.
The active chemical process is called a polarity swing that occurs naturally at nearly room temperature, drastically reducing the need for heat during natural gas sweetening. Scientists estimate this method could cut the amount of energy needed to complete the sweetening process by at least 10 percent.

Here is the part beyond saving natural gas for process heating from David Heldebrant, corresponding author and project manager, “Applying ASSR to natural gas sweetening could result in a more environmentally friendly process because hexadecane is non-toxic.”  That’s very good news, aside from not wanting a lot of hydrogen sulfide getting out of control.  “We also anticipate chemical sorbents could last longer because they are not subjected to repeated heating and cooling, which degrade the sorbent,” Heldebrant adds.

The paper is published in the March 11 online issue of the journal Energy and Environmental Science and patents are pending on this technology. The technology is already available for licensing worldwide.

That just leaves recycling the hydrogen sulfide back deep into the earth’s crust, unless someone figures out a way to made worthwhile use of it as well.  Which would come as no great surprise . . .

How much natural gas is up for conjecture.  Contaminated gas reserves haven’t been logged or reported in great or accurate detail.  But estimates range from 16% of the world’s total reserves on up to 30%.  Keep in mind these are hypothetical estimates.  How much gas has been drilled through and ignored could be far more than these estimates.  Whatever the number is it hardly matters, it’s a huge resource if the natural gas can be cleaned up.

Brian Wang at NextBigFuture spotted the press release from Armington Technologies, LLC’s affiliate Tenoroc, LLC has developed a unique method of cleaning or separating gases using curved nozzles. More in a moment . . .

Here’s the problem today, natural gas can be cleaned by percolating it through massive tanks of absorbing liquids, a method called Acid Gas Removal (AGR), or to a far lesser used extent by membrane filtering. AGR plants occupy a very large area, limiting their use in remote land based locations and especially on offshore platforms where space is very expensive to build.

The AGR kind of process can only work for a limited time before cleansing becomes too costly.  AGR plants require a great deal of heat and energy to remove the absorbed contaminants from the absorbing liquids in a process called re-boiling. The frequency of re-boiling increases with higher levels of contamination. During the re-boiling process the volatile absorbing liquids, as well as any natural gas that was absorbed, are released into the atmosphere. Those emissions are significant greenhouse gases that contribute to atmospheric pollution. The natural gas losses are like cash vented off. The absorbing liquids that are emitted must be continually replaced, adding to the processing costs.

Now some AGR type systems and newly developed membrane processes can process higher CO2 contamination levels than the conventional AGR plants. But these systems have not been selling, presumably due to the processing and capital expense.  It would take a very high price guarantee to invest in this kind of natural gas cleaning technology.

The technology Tenoroc’s been developing is a curved nozzle technology. These small nozzles, with no moving parts, generate and exploit centrifugal forces that can exceed conventional spinning centrifuges, achieving improved separation levels and the phase change of rapid gas pressure changes. That divides Tenoroc’s nozzle technology into two areas, the “condensation based separation” and “gas-to-gas separation”.

Natural Gas CO2 Separation By Centrifugal Force and Phase Change. Click image for more info.

The explanation is quite simple for an elegant idea.  Envision a section of coiled spring shaped tube. The condensation based separation expansion occurs within the nozzle as one gas in a mix of gases phase changes to a liquid. Now the liquid CO2 and remaining natural gas constituents are flowed through the curve in the nozzle where centrifugal energy forces the liquid, which is heavier than the gas, to the outside wall where it exits through the outside wall outlet.  That performs the gas-to-gas separation.   One assumes the natural gas simply flows out the end of the spiraled curved nozzle or perhaps is bled off the inside of the tube in a working unit.

This is a link to the company’s animation.

Note than centrifugal force as related to gravity can be extreme.  The gravitational force generated can be in the multiple millions, depending upon the size of the nozzle, its length of arc and degrees of arc travel.

Paul Donovan, Director of Technology Development explains the market positioning and marketing effort; “We see our niche in the natural gas industry in applications where there are high levels of contamination, too high for today’s methods of cleansing natural gas. We also hope to improve or supplement cleansing on less contaminated natural gas currently being processed. Our small footprint and versatility in placement is an added bonus. The key to commercialization will be our ability to license our technology to a strategic partner that provides equipment and service to the natural gas processing industry. We intend to begin demonstrating our prototype immediately as a first step in this process.”

The company also believes the design has the potential ability to resolve the other major natural gas contaminant, hydrogen sulfide.  Of particular interest is the CO2 cools releasing heat.  When the cooled CO2 is used to cool the incoming gas flow the energy of compression is reused, saving on the cost of operation.

It interesting to note that the company’s initial interest wasn’t natural gas cleaning, but the market demand was noticed, the differences in CO2 and natural gas phase change temperatures used taking ingenuity into innovation for a hugely beneficial natural gas reserve gain.

Access to marketable natural gas reserves with CO2 and hydrogen sulfide cheaply removed is going to have an enormous impact.  In North America the numbers are essentially hints of the potential.  What’s better known are the North Sea, the Corrib Gas Field off Ireland, and the Scotian Shelf near Sable Island.

Somewhere in every oil and gas company executives are checking to see where they have natural gas that was overlooked because of contaminates and wondering when they’ll see pricing and specification on the new separation process. With the current U.S. shale gas reserve technology, the likely first adopters might be in Europe where gas is much higher priced.

Another plus is that a new volume of CO2 is going to become available for secondary and tertiary oil recovery from oil reserves.

By any description, this is a major development in the oil and gas business.

Siluria’s CEO Alex Tkachenko, says 95 percent of Siluria’s effort is now devoted to the methane-to-ethylene process.

Converting methane directly to valuable chemicals and liquid fuels is an industrial challenge that has defied the best minds in chemistry.  But knocking off one of the four hydrogen atoms arrayed around methane’s only carbon atom requires so much energy that the process tends to run out of control, burning up the entire gas molecule leaving just CO2 and water.

Siluria’s development from Belcher’s work is a catalyst that efficiently turns methane into ethylene, the feedstock underpinning more than two-thirds of global chemical production.

Tkachenko reports Siluria has succeeded with a brute-force trial-and-error process that tested novel compounds with catalytic potential. “The problem is too difficult to analyze your way out of. We’re overwhelming the problem instead with a simple, sturdy experimental technique.”

Charles Musgrave, a computational chemist at the University of Colorado in an interview with MIT’s Technology review covers some of the problems and history, “The quest to activate methane’s chemical potential has left a path of unrequited chemists. Catalysis design firm Catalytica spent five years and over $10 million to develop a sophisticated catalyst and process to turn methane into methanol, but its process proved too costly.  In 2008, Dow Chemical put up over $6.4 million for methane activation research led by teams at Northwestern University and the U.K.’s Cardiff University. “Dow had gone as far as they could. It’s a sign of how hard this problem really is that they’re going out and funding others in this way.””

Virus Built Catalyst Nanowires. Click image for more info.

That level of recent interest and decades of flirting with the matter brings considerable skepticism to the Siluria claim.  But Siluria has enlisted viruses to handle the catalyst design. Its workhorse is a virus that’s 900 nanometers long and just nine nanometers in diameter. The virus can serve as a template for the formation of equally small nanowires when it’s exposed to metals and other elements under the right conditions. Siluria can create an endless variety of potential catalysts by mutating the virus’s protein coat so its surface guides nanowire formation, selecting the ratio of elements introduced to that template, and tweaking the timing and conditions of the process. To detect efficient methane activation catalysts, Siluria then subjects these structures to screening.

Now Siluria is out in the open.  The Menlo Park, California-based firm, which raised $3.3 million from venture capital firms last year expects to announce further financing this Septemeber.  With a novel nanowire catalyst that it believes could be commercially viable Siluria could offer a process that’s highly valuable.

Erik Scher, Siluria’s vice president for R&D explains why, Siluria’s nanowire catalyst can activate methane at “a couple of hundred degrees” cooler than the best existing catalysts, which he says operate between 800 °C and 950 °C.  That will help calm the runaway hydrogen atom exit from the methane molecule.

Scher continues – relatively mild conditions should deliver two benefits. Not only should they keep the methane from burning up, it also means that the resulting methyl radicals are more likely to stay on the surface of the nanowire in the company of other methyl radicals, which can then react with each other to form ethylene rather than flying off the nanowire to engage in other reactions–including ones that degrade the precious ethylene product.

Tkachenko says the catalyst, if applied widely to ethylene production, could cut costs to the chemical industry by tens of billions of dollars annually and reduce global carbon-dioxide emissions by over 100 million tons per year. The company hopes to use its anticipated financing to move into the pilot process next year. Validation with a lab scale reactor running continuously for thousands of hours would then lead to commercial demonstration plants, hopefully in less than five years – an aggressive pace for a major chemical process.

Now keep in mind that methane at CH4 is about as rich in hydrogen ratio as molecules come.  Getting to ethylene is a huge step where going on to larger molecules can be easier.  Scale will come into play as well with the obvious energy input needed to keep the process going.  It’s not a done deal yet.  For scale to work the facility costs could run into tens or maybe hundreds of millions of dollars for the investment.  The process has to work and be efficient.

The advantage lies in prices for oil compared to natural gas.  The price of a BTU from natural gas today is about one third of a BTU from an oil product. Methane is also abundant both in fossil form, in methane hydrates and its produced from biomass in most every digestion process of bacteria and animals.  Coming up with methane isn’t especially difficult.

But getting that wondrous hydrogen rich carbon based methane molecule sized up into more workable carbon based sized molecules is a puzzle of great significance.  If Siluria pulls it off in low cost commercial scale, hydrocarbons future role, perhaps in an ever-increasing share of renewable forms, would be assured.