Luca CEO Robert Pfeiffer says he anticipates that Luca will get permits for larger-scale pilot projects of “restoring” existing wells in the next four to six months.  Luca, one of many start-up companies pursuing technologies to make fossil fuels cleaner has acquired 1,350 coalbed methane wells, which have been sold by their original owners because they are no longer productive enough.

The principle Luca exploits is anaerobic microbes living in subsurface coal, gas, oil and shale reserves for millions of years, feeding on hydrogen-rich organic matter and producing natural gas. Commercial drilling and extraction exposes these anaerobic microorganisms to oxygen by taking water out of the formations and removing essential nutrients that support microbial growth. As a result, the production of biogenic natural gas slows or in some cases ceases. Over time, water is replaced in the geologic formation by natural recharge providing an environment that allows the microbes to once again produce natural gas at low rates.

Luca uses its proprietary technology to restore formation habitats to conditions that enable existing microbes to produce economically significant rates of natural gas at accelerated production volumes.  Then the company harvests this newly created natural gas and delivers it to the national grid via the existing pipeline from the pre depletion era of the wells.

Luca Technologies Underground Process. Click image for more info.

Unlike the oil and gas industry’s extraction methods in which production peaks then steeply declines as stored hydrocarbons are depleted, Luca “gas farms” can reliably produce low-cost clean energy for decades and reuse existing wells and infrastructure to create, extract and transport the natural gas.

How big a deal could this be?  Pfeiffer explains, “Farming” natural gas from depleted wells in the Powder River Basin in Wyoming and Montana alone could produce more gas than the annual consumption in the U.S., said Pfeiffer. Microbes have converted one-hundredth of 1 percent of the coal into methane in existing wells. Luca has reached 3 percent conversion in its labs, which would not happen in actual wells but it reflects the potential of the process.  It could be a very big deal indeed.

The potential, which raised $76 million in equity in late 2008 for Luca, of tapping this stranded natural gas in coalbed methane wells is significant.

When Luca identifies a depleting area or well as a natural gas farming candidate, it withdraws water from the well, transfers it to a mobile nutrient module to replenish essential vitamins and nutrients vital to sustaining microbial community health. The water is then recycled back into the well through existing infrastructure and the mobile nutrient module is moved to other wells to provide nourishment to new subsurface habitats.

Luca then temporarily shuts in the well for an average of one month to allow natural microbial populations to flourish. During this “dwell” period, the now activated microbes begin producing significant amounts of natural gas. Luca harvests the natural gas using the existing system. This cycle of restoration and harvesting enables Luca to produce natural gas from depleting wells for decades.

Its long been known that a portion of natural gas is produced by naturally occurring subsurface microorganisms. Luca’s founders discovered that certain coalbeds, organic-rich shales and oil and gas reserves were teeming with microbial life capable of producing economic and commercially significant volumes of natural gas. Based upon this discovery, Luca founders recognized that integrating the disciplines of oil and gas with biotechnology could produce a solution to the global demand for clean, affordable energy.

Here’s a list of nutrients Luca uses in its natural gas farming process in the Powder River Basin to replenish underground habitats depleted by previous drilling operators: Minerals of calcium added as calcium chloride, magnesium added as magnesium chloride, phosphate added from magnesium phosphate, phosphoric acid, calcium phosphate, sodium phosphate, potassium phosphate, or sodium tripolyphosphate, potassium added as potassium chloride.  Vitamin B-12, Niacin, Thiamin, Riboflavin, Biotin, Pantothenic Acid, Folate are added.  Proteins and perhaps activators, casein hydrolyzates, yeast extract, brewer’s yeast, soy protein, and peptones.

Looks like a nutritionist’s prescription, but Luca isn’t done yet.  Add in some vitality things like glycerol, weak organic acids, formic acid, acetic acid, propionic acid, butyric acid, lactic acid and decanoic acid.  A smorgasbord of supplements!

One has to wonder, just what does a concoction cost to treat a well, how often does a well need to be fed again, does the feeding peak with production running along on its own, and do any of the feedstocks get back to the surface for recycling?

There is an enormous amount of natural gas formation types, from landfills to deep hot rocks.  Somewhere between the extremes is an opportunity that Luca has figured out how to make pay.
If Pfeiffer is right about the potential recovery, and at least in some small part they’re correct now, the reserves in place could multiply dramatically.

Since it’s mostly all proprietary and intellectual property the hard details are out of reach.  But many a gas producer has to be looking over at Luca wondering . . . just how do I make use of that technology?  Many a consumer must be relieved as well . . . natural gas is by no means a short term fuel supply, its here to stay.

Case Item No. 1:

In the U.S. alone, the combination of horizontal drilling and reservoir fracturing services becoming more affordable has moved up the U.S. reserve by 35% in existing fields of 2007 to 2009.  Fracking and horizontal drilling technology is working at the source of the methane fuel system.  The U.S. oil and gas business is leading the way. John Curtis, a leader of the U.S. Potential Gas Committee says, “Our knowledge of the geological endowment of technically recoverable gas continues to improve with each assessment. Furthermore, new and advanced exploration, well drilling and completion technologies are allowing us increasingly better access to domestic gas resources – especially ‘unconventional’ gas – which, not all that long ago, were considered impractical or uneconomical to pursue.”

Just five years ago the U.S. was planning for importing natural gas. But now it’s expected that the U.S. will become an exporter.  Investments in Russia and Qatar have come up without markets for now.  As the U.S. industry gathers experience, the estimates are sure to rise in the coming years.  Today the independent estimates have over 90 years of supply on hand and as more reservoirs are discovered the reserves will climb.

Most of the gains come from ‘shale’ deposits. Stephen Holditch, professor of petroleum geology at Texas A&M University is being quoted that transferring the technology currently used in the United States would increase worldwide available gas reserves nine times.  Based on the American experience, Holditch estimates total world shale reserves as being more than 16,000 trillion cubic feet (tcf). Annual gas consumption of the developed economies is currently around 50 tcf. 50 into 16,000 is 320 years.  Holditch suggests there are reserves of some 500 tcf in Western Europe, 2,500 tcf in the Middle East and 3,500 tcf in China.

Case Item No. 2:

Naturally occurring methane hydrate may represent an enormous source of methane, the main component of natural gas, and should ultimately augment conventional natural gas supplies.  The National Research Council has just released the prepublication pdfs (chapters are separate downloads) of their report on their site.  With several commercial challenges before production, the technical challenges are now seen in the report as surmountable.  Methane hydrates look practical, and while costly to start, the production costs can be expected to lower over time.

Methane hydrate is a frozen solution of water and methane.  It’s been found from as far south as beyond the U.S. Gulf of Mexico to the equator to the Alaskan North Slope around the Arctic Ocean.  The methane hydrates are expected to occur in the continental shelves across the planet and on shore at or near permafrost areas.  Methane hydrate reserves aren’t ‘credible’ yet; the rules of assessment are still in debate.  The known reserves are substantial and extrapolation yields huge numbers.

The key pages of the National Academy’s Methane Report start at page 18 and run to page 48 with 6 pages of references.  Like all academic reports, the materials and sources are likely dated, but one can fairly project that the research in industry isn’t so far advanced as often seen in other fields.  This is in part because the industry has carefully avoided methane hydrate and the methane hydrates are found in a vast array of structures.  The water is frozen and can be supportive of the surface.  The methane distribution appears in at least two forms, one where free gas enters and inhabits a reservoir and second where hydrates are formed from gas dissolved into the water.  The State of the Science section is fascinating science reporting, well worth the download and the few minutes for reading.  The scientific papers noted in the report lack web links as the only inconvenience.

Methane as Located in the Methane Hydrate. Click image for more info.

So far there are three methods in research for extraction plus the novel ideas.  They are depressurization, thermal or warming, chemical and the novel.  Novel ideas are already in patenting proceedings across the world.

Case Item No. 3:

Just to ‘throw a little methane on the fire” if you will, Monday saw Dr. John Dunbar, associate professor of geology at Baylor, and his team receive additional U.S. Department of Energy grants funds to continue their successful research of a new methane hydrate search method that they’ve adapted for use on the seafloor to find a potentially massive sources of methane hydrate.  The team used an electrical resistivity method to acquire geophysical data at a site located roughly 50 miles off the Louisiana coast. The researchers were able to provide a detailed map of where the methane hydrate is located and how deep it extends underneath the seafloor.

Located in an area called the Mississippi Canyon, the site is about 3,000-feet-wide, 3,000-feet under water, and has both active and dormant gas vents. Scientists have been researching the site since 2001, but have not been able to ascertain where the hydrate is located nor how much is there until now.

Professor Dunbar said, “The conventional search methods have been fairly effective in certain situations, but the resistivity method is a totally different approach. The benefit to the resistivity method is it shows the near-bottom in greater detail, and that is where the methane hydrate is located in this case. This research shows the resistivity method works and is effective.”

While the measurement of resistivity has been used for some time, the method has seldom been used at deep depths. The new application method showed researchers that the methane hydrate was located only in limited spots, usually occurring along faults under the sea floor. Dunbar said the method also showed the methane hydrate is not as abundant as previously thought at the Mississippi Canyon site.

Dunbar and his team dragged a “sled” – a device with a nearly one-kilometer-long towed array – back and forth over the site, injecting the electrical current. Sediment containing methane hydrate within its pores showed higher resistivity, compared to sediment containing salt water. While the measurement of resistivity has been used for some time, the method has seldom been used at deep depths.  With the new funds Dunbar and his team will reconfigure the towed array and shorten the length of it to about 1,500 feet. They also will cluster sensors around certain areas on the array, which will give researchers a clearer picture of how deep the methane hydrate extends and will allow them to create a three-dimensional picture of the underwater site.

U.S Geological Survey estimates of methane hydrate is now at 200 trillion cubic feet of natural gas.  At just 1% recoverable, that more than doubles the U.S. natural gas reserve.  Extrapolated worldwide would have a far larger effect.

Just three items make a substantial case.  The CH4 methane molecule is abundant and can also be made biologically and chemically.  It’s a great way to use hydrogen rich carbon from fuels cells to heavy equipment.

For those not watching the close up to shore part of the Gulf of Mexico, its been thought of as pretty well drilled out for decades.  But now at depth past 25,000 feet estimates for the size of the discovery range from 2 trillion to 6 trillion cubic feet of natural gas, rivaling the largest gas finds ever made in the Gulf.  The region is the major supplier of U.S. natural gas. The company is saying it will have to do further drilling to confirm the resource potential.  But the early snapshot drilling is confirming the pre drilling research.

The drill site is called Davy Jones.  The other newsworthy point is it’s a very deep drilling effort.  The Davy Jones well went to 28,263 ft measured depth in 20 ft of water on South Marsh Island Block 230. Pipe-conveyed wireline logs went as deep as 28,134 ft. Wireline log results indicate a combined 135 net ft of hydrocarbon-bearing sands in four zones in Eocene-Paleocene Wilcox. All four zones are full to base, and two contained a combined 90 net feet of sands. The Wilcox suite logged below 27,300 ft “appears to be of exceptional quality,” McMoRan said.  That’s sands folks, not rock.

McMoRan will deepen the well to 29,000 ft to test other objectives.Of note, this well is similar to many deep water drilling efforts that must pass through layers of salt seen in the Gulf and the huge discoveries off the coast of Brazil.

The discovery points out the potential for yet another frontier for oil and gas development in an area of the Gulf of Mexico called the Outer Continental Shelf that has been drilled extensively for nearly a century.  The difference is the depth and the quality of the pre drilling seismic studies.  The studies plus the newly drilled well suggest the same rock and sand layers that in recent years yielded major oil and gas discoveries several hundred miles out in the Gulf may be equally rich with oil and gas in shallow water areas, where exploration and production is much easier and cheaper.  There might be a groan heard from those deep water investors if oil prices plummet someday.  For U.S. refiners and consumers this is great news.

It’s sure to draw investment back to shallower water depths.  This will be another energy stimulus program run by private citizens.  There is even some challenge, current drilling and production technology will be tested by the extreme temperatures and pressures found in miles-deep wells required to reach the resources, and development costs could be high.  Compared to land based development, maybe so, yet much is already known from the way out in the Gulf, deep-water efforts that are in hot high-pressure reservoirs that are economically viable even at under $60 oil.

McMoRan Co-Chairman James R. Moffett said in a conference call discussion on Monday it would take at least 10 wells at a cost of $150 million to $175 million each to bring the 20,000-acre field into production.  Moffett believes if development drilling confirms what the first well has shown, “this is going to be a huge reserve.”

The U.S. Minerals Management Service, the bureaucracy with oversight for offshore oil and gas production in federal waters, describes “deep water” as any oil and gas development in depths of 1,000 feet or more. The outer continental shelf comprises shallow water closer to shore.

The major independent oil companies like Chevron, ExxonMobil and Shell have left the Gulf of Mexico Shelf in recent decades, drawn to the though of much larger and more profitable fields in the deep water, as well as federal royalty relief programs meant to spur development farther offshore. They sold their offshore leases on the continental shelf to smaller firms with lower operating costs that could still turn profits on the smaller fields.

Tyler Priest, director of Global Studies at the Bauer College of Business at the University of Houston, who has written about the history of offshore oil and gas development in the Gulf of Mexico said, “This is a real breakthrough.”

The mid sized oil industry has been plotting to get investment into close continental shelf leases for years.  The wait for high enough oil prices to cover investments has ended.  For the rest of us something significant is also now apparent, the idea that the best production from the Gulf of Mexico is over isn’t.  Priest says, “It’s the goose that keeps on giving, apparently.”

The results also point up the potential of the rest of the U.S. coast and continental shelf.  There is a lot of Gulf of Mexico still not available, as well as the entire east and west coasts.  There is also the huge area around Alaska.  None of these would come cheap, but $80 per barrel oil is tolerable if it keeps the $150 a barrel price way off into the future.

The ultra-deep sub-salt reservoirs in the Gulf of Mexico have huge potential. The fact that they have discovered hydrocarbons in reservoir quality rock at that depth is very big news.

$80 oil is also very solid ground for the best ideas in alternative fuels, too. The fossil fuel powerdown to new technologies powerup is going to take decades even if a miracle occurs tonight.  The U.S. and the entire consuming world needs more supply to get the time for the economy to adjust to changes.  With the majors in deep water, the mid sized firms in shallower water and lots of ground to yet cover, the issue could be the resources to keep up.  But the throttle is on from government intervention.

As one commenter JReynolds, to the breaking story at the Houston Chronicle puts it, “Did Congress help find this? Did Obama help find this? Not just no. But you can bet Congress and Obama will now confront this partnership gun-in-hand, demanding their skim from the profits.”  Now that’s something to worry about.

A catalyst manufactured by the American chemist Roy Periana over ten years ago from platinum and simple nitrogenous bipyrimidine effectively creates methanol, but only supports the reaction in a soluble form. That means that the catalyst — which chemists refer to as a homogenous catalyst — subsequently needs to be separated off in a laborious, expensive and somewhat wasteful process.

Scientists at the Max Planck Institute for Coal Research and at the Max Planck Institute of Colloids and Interfaces might make it worthwhile to harvest or tap into previously inaccessible natural gas resources. They have developed a catalyst based on Periana’s work that converts methane to methanol in a simple and efficient process.

The natural gas burned off throughout the world alone could more than satisfy Germany’s requirement for natural gas.  It is not cost-effective to lay pipelines to remote or small natural gas fields; nor is it worthwhile to access the methane in coal seams or in gas sands, or which is burned off as a by-product of oil production.  Then there is the methane in gas hydrates to consider as well.  There is a lot of natural gas out there to harvest.  It’s just too expensive to liquefy the gas and transport it by trucks, trains or in tankers.  Chemistry research has so far been unable to offer an economic solution.

Ferdi Schüth, Director at the Max Planck Institute for Coal Research in Mülheim an der Ruhr and his colleagues have been working with Markus Antonietti and his team at the Max Planck Institute of Colloids and Interfaces in Potsdam to develop a catalyst that might change all this.

Schüth says, “When I saw the structure of covalent, triazine-based network (CTF), I noticed the elements which correspond to its bipyrimidine ligands. That’s when I had the idea of manufacturing the solid catalyst.”

The chemists in Potsdam synthesize the CFT. “This solid is so porous that the surface of a gram is approximately equivalent in size to a fifth of a football (soccer) field,” says Markus Antonietti. The researchers in Mülheim have built a voluminous lattice, inserted platinum atoms so the catalyst oxidizes the methane efficiently to methanol when immersed in sulfuric acid.  Forcing in the methane at 215º C yields more than 75% of the methane into methanol.

Methane to Methanol Catalyst -Max Plank Institute. Click image for the largest view.

Schüth explains, “It’s much easier with our heterogeneous catalyst,” they filter out the powdery platinum and CTF catalyst, and then separate the liquid acid and methanol in a simple distillation process.

To get closer to a large-scale technical application, the team is now attempting to enable the process to work with reactants in gaseous rather than soluble form. “We are also looking for similar, even more effective catalysts,” says Schüth. “We have already found more efficient homogenous catalysts with ligands other than bipyrmidine.” They are now using these as a model for simple, easy to manage catalysts like the CTF and platinum powder.

Methane is abundant in low concentrations, and the rich deposits, like gas formations and methane hydrates are widespread and in often remote or deep or inaccessible locations in sizes that preclude the investments needed for pipelining or liquefying, both capital-intensive operations for reaching markets.  An example exists; in North America natural gas pipelines are widespread with markets also widespread already well connected.  Eurasia though, has little gas near the markets, at great distances to the fields in Russia or the Middle East with large-scale development still underway or planned and even hoped for.  It’s a very different situation.  Europe will likely chose even more expensive imported liquefied natural gas to meet its demand.

Many believe that natural gas is far more abundant than reality makes clear.  By no means has the industry invested as much in secondary recovery as in the oil field operations.  In North America where the leading technology innovations are found, the effort to find and hook up new gas finds simply makes secondary recovery a sure way to lose money.

Even methane hydrates, a rich source of methane fuel is abundant, widespread and technologically challenging to recover.  Perhaps the team’s new catalyst and process have a use there as well.  Something much less expensive and ecologically kind is needed to harvest methane hydrates.

The Max Plank team is well on to something, just how it plays out has more opportunity than first impressions suggest.  Let’s hope they get the gaseous catalyst and process worked out for scale up.  Methane is a valuable thing to waste, especially on the European continent.

The team’s paper, Solid Catalysts for the Selective Low-Temperature Oxidation of Methane to Methanol appeared in the Volume 48, Issue 37, September 1, 2009 of Angewandte Chemie International Edition / DOI: 10.1002/anie.200902009.

The discovery was made at an altitude of 4,062 meters above sea level in Qinghai province’s Tianjun county, where some areas have perpetually frozen soil.  China, the country with third largest frozen soil area has a frozen soil area of 2.15 million square kilometers with prospective natural gas hydrate reserves of 35 billion tons of oil equivalent.    According to the MLR, this is the first find of this kind in low-latitude onshore areas in China, providing strong evidence that the country’s frozen soil area could have abundant natural gas hydrate reserves.

It’s that low-latitude location that helps.  Being farther to the south than other locations access is enhanced and comes at lower costs.

Natural gas hydrates or methane hydrates are also called “flammable ice.” It is considered one of the earth’s major untapped energy resources. It could be an important and cleaner substitute for traditional energy sources such as oil and coal.

Ignited Natural Gas Hydrate. Click image for the largest view.

It is estimated that natural gas hydrate reserves in the world are almost twice the reserves of traditional natural gas, oil and coal in terms of oil-equivalent tonnage, or 50 times traditional natural gas reserves.  There is a lot of the stuff up or in there.  But natural gas hydrate has a long way to go before it can be developed on an industrial scale because of the need to solve geographic and environmental protection matters.

The nature of hydrate deposits is they can exist in deep-water areas or frozen-soil areas of the world due to its volatile nature.  Warm them up or depressurize them and they go to the gas state and escape.  Freed and lost to the atmosphere, methane really is a “green house” gas that takes a long time to degrade.  The water released is hardly a concern so far.

Zhang Hongtao, the engineer general of the MLR said these kinds of obstacles means it would take China 30 years to prepare for an offshore deepwater exploration and development of natural gas hydrate, and at least 10 to 15 years to start even tentative exploration of onshore reserves in their frozen-soil zone. He cautioned that large-scale commercial exploration and development of natural gas hydrate might devastate the fragile environment and eco-balance of the Qinghai-Tibet Plateau.

But, Wen Huaijun, a senior engineer of the Qinghai Provincial Bureau of the China National Administration of Coal Geology (CNACG), said that Qinghai’s natural gas hydrate finding has an average depth of 130 to 300 meters, providing relatively favorable conditions for exploration and development, while echoing Zhang’s environmental concerns.  There is a little political push-pull underway already.

China is at a point where high altitudes in the lower latitudes could allow some research into recovery methods.  While their news isn’t touching on the matter they surely must be entertaining just what experiments could be undertaken.  The opportunity for other nations and companies to get involved is unknown, but it would certainly help world prices if China does share, open up or join with others to seek the best methods of hydrate recovery.

It might seem paradoxical that natural gas hydrates pose such a challenge.  For the most part, the large known deposits are under deep cold water.  It would take a great deal of heat to thaw them out and controlling the releases would be problematic at best and disastrous at the worst.  The technology seems straight forward, and likely will turn out to be so when the interactions at depth can be forecasted, tested and known.

That makes getting on firm ground at lower latitudes and important advantage as theories, forecasts, and testing in the course of research are not going to be done on billion dollar deep water drilling rigs anytime soon.

The opportunity is there, still likely quite cold, thin air, and difficult.  But the research potential and trying the new ideas possibly just got a lot cheaper.

Exxon Mobil chief executive Rex Tillerson said during an analyst meeting earlier this year, “Clearly, we anticipate that natural gas will grow much faster than oil or coal. So we see a pretty healthy demand out there in the future for natural gas globally, but even here in North America.”  Agreed, the natural gas is there, and Exxon is busily figuring out ways to cut those costs, which is the point of today’s post.

In the 1980s, frac jobs could take months. Currently a complicated well frac typically takes a couple of weeks.  Backed up by ExxonMobil, Tolman developed a method to fracture a Piceance Basin well in only three days, and he thinks he can compress it to 24 hours.  The key is to conduct every activity simultaneously.

Tolman persuaded his colleagues to experiment in the face of everyone thinking that such an undertaking was impossible.

In the 1980s, Tolman noticed something strange while working on a natural gas well in La Barge, Wyoming.   Natural gas was flowing out of the well without pushing out or damaging the sensing and control wire that operators had dropped into the well.  Years later, while descending an elevator at ExxonMobil’s corporate building in Houston, Tolman had an idea. Why not use this phenomenon to perform simultaneous functions on a well? So that’s exactly what he is doing in Colorado’s Piceance Basin.

At the Piceance Basin well sites workers position the wire in the well. The carrier water is valved to flow and the pressure is built up. The frac specialists then prepare to shoot electronic pulses from the wire. They watch colorful computer screens to monitor pressure created by pumping a mixture of water the sand and chemicals into the well. When the pressure is just right, they shoot a frac gun to punch out a hole through the well pipe into the rock.  That’s when the rush of pressure splits open rock fissures and the sand flows out to fill the fissures with special chemical compounds to clean and preserve the work.  When the fracture is compete, they flow rubber balls into the pipe well to plug the newly shot frac holes, and immediately repeat the process.

Fracturing Equipment Piceance Basin - ExxonMobil

All the while specialists are watching those monitors connected to the wire.  Knowing when to shoot, how long to flow water sand and chemicals and just when to stop and flow in the rubber balls to stop the action comes from the experience that makes this kind of thing work.

Tolman’s team will fire the frac gun as much as seven times a day or more. While one gun is shooting the first well, they will load the second gun for well No. 2, back and forth, so that the men and the equipment are constantly working.  But there is lots more going on.  Men bring and move the materials, operate pumps and monitor little red lines on computer screens. The work jobs must happen simultaneously, in a carefully orchestrated ballet, to keep the well costs low — and profit high enough — to be worth the effort of the country’s largest oil company.

ExxonMobil has drilled 10 holes in the Piceance (pronounced PEE-awns) Basin, five of which already produce natural gas. The company’s rigs don’t have to be reassembled between wells. Instead, the drill can move horizontally and laterally to reposition. This speeds the process and cuts the cost of rig crews.

ExxonMobil controls the sweet spot on the Piceance Basin land owned by the Bureau of Land Management.  Plenty of other natural gas producers operate wells there, too.  And ExxonMobil has Halliburton employees working on a contract so the know-how is sure to spread, an old oil patch tradition of sharing what works.

It matters, as natural gas is the go to fuel for any transition of the energy and fuel market.  It will take years to recreate an energy system in the U.S. no matter what the politicians and media followers want you to believe.  With innovations adopted by ExxonMobil and shared more of the new drilling technologies the U.S. has plenty of natural gas. According to the Energy Information Association, proven U.S. natural gas reserves in 2007, the most recently available data, have risen by one-third to 237,726 billion cubic feet just since 2002, as the new techniques were becoming popular.

Last summer natural gas prices rose above $13 per thousand cubic feet while today natural gas future prices trade well below $4 per thousand cubic feet a much bigger drop than crude oil.

ExxonMobil began a significant Piceance Basin expansion in 2007, after scientists developed better drilling and fracing methods that could make the operations profitable. Exxon now operates seven rigs in the Piceance Basin and produces 100 million cubic feet a day. Project executives have said the company could eventually increase to 1 billion cubic feet a day.  With interests on 300,000 Piceance acres, Exxon Mobil is holding enough gas to heat 50 million homes for a decade.

Many, “experts” reporters and others will say there is an energy shortage usually in the form of something like peak oil. But when you look a little deeper its clear that innovation, creativity and an open corporate culture to some experimentation can have a big result.  It may seem an ExxonMobil benefit, but all those new reserves mean that consumers can count on supply at reasonable prices for a very long time to come.

Before we start, hydraulic fracturing is packing water, some solvents, and strong sand and special chemicals into the rocks thousands of feet down so that oil and gas can flow back out.  It’s a kind of miniature, slow motion cracking of the rocks much further out from the little well hole.  One could also call it an explosion, but it takes hours, running into days to build up the pressure, to get some cracking and pack the sand into the fissures.  It turns a little hole into solid rock into a hole in lots of little rocks.

It’s just critical to keep this technology in use and further development.

Hydraulic fracturing has a 50 year history beginning with quite simple pressure buildups to today’s highly sophisticated multi directional wells in rocks that only a half decade or so ago were considered hopeless repositories of petroleum.  Today, using hydraulic fracturing a well or even a set of wells can release huge quantities of natural gas.  This can easily be seen in the natural gas price at the home meter to fertilizer for food and investments in even more production.  In the coming months more technology is coming and is being blended with technology that looks into the earth to guide where more effort should be applied.

All that, the potential and the world’s lowest prices of natural gas for Americans are at risk from a disaster of rearranging (and adding) regulations.  The Federal proposal is so bad that the amazing situation of business preferring a single regulatory framework over 50 regulations from the states is not preferable.  Yup, government can make a disaster from nothing at all, which isn’t amazing at all.

The matter is a fully Democrat sponsored attempt to place regulations of the Safe Drinking Water Act thousands of feet down below any source of water for human use.  The bills, a House version and the Senate versions are very similar, which cautions one to realize this is a concerted attempt to subvert the existing framework of petroleum operations and regulations into a whole new field of bureaucratic interference.

Just to make things worse, the Feds propose not to unify regulations; they want to ADD a Federal layer.  IHS Global Insight’s study, “Measuring the Economics and Energy Impacts of Proposals to Regulate Hydraulic Fracturing,” predicts the number of new U.S. wells drilled would plummet 20.5 percent in the first five-year period.  That would potentially reduce natural gas production by about 10 percent from 2008 levels by 2014, a mere 5 years out.

Remember the last marginal buyer’s impact on prices?  Carving off 10% of supply isn’t going to be cheap for heating homes, running business and industry or generating electricity.  Someone is passing put stupidal capsules in D.C.

There are problems, to be sure. In the fight last month the Ground Water Protection Council released a study that finding regulation of oil and gas field activities, including hydraulic fracturing, is best accomplished at the state level where regional and local conditions are best understood and where state regulators are on hand to conduct inspections and oversee specific operations like well construction, testing and plugging.

The Ground Water study is an excellent piece to grasp what’s been going on and raises the issue about why the Feds are digging here for more power anyway.  The history and background discussed go far to understand the process and that a few states are behind.

Is it serious?  If you live over a leaking well it is, but those aren’t so common as many would have us believe.  What is an issue is the control and enforcement of the law on the books.  Some states do lack enough oversight.  Arguments over who is to pay for control and cleanup is usually in the domain of lawyers consuming time and often more money than the clean up.  Drives people nuts, understandably, but is more regulation and economic costs the answers to the problems?

Today in the U.S., where over 95 percent of wells are routinely treated using fracturing, the impact of eliminating hydraulic fracturing on production would be “permanent and severe,” the IHS report notes.  The production slippage would be significant.  Part of the new regulations is to restrict the types of materials used to fracture rock.  You and I both know better than to think any Congressperson(s) can better decide what’s appropriate to use.  But IHS has figured that the proposed regulations would impact gas production falling 4.4 trillion cubic feet or 22 percent, while oil production could slip 400,000 barrels per day or 8 percent.  These are major numbers, tearing out more than the marginal buyers, driving prices to unpredictable new highs.

API President Jack Gerard said, “More than one million wells have been completed using this technology. Unnecessary regulation of this practice would only hurt the nation’s energy security and threaten our economy.”  That’s public relations nicety comment.

In raw numbers the study found elimination of the use of hydraulic fracturing would be catastrophic to the development of American natural gas and oil, with a 79 percent drop in well completions, resulting in a 45 percent reduction in natural gas production and a 17 percent reduction in oil production by 2014.  Those are real American jobs.

Everyone world wide would be affected.  Today the U.S. is a very small importer of natural gas.  The proposed bill would certainly change that forcing the U.S. into the world natural gas market in a big way.  No one, other than some special interests, injured parties frustrated at state responsiveness and a raft of natural gas exporters stands to gain.  And the last ones to benefit would be the injured Americans, anyway.  Just imagine the resentment of the world at the U.S closing in even more production.  This is a way past being a stupid proposal.

But in the end the IHS report is a model, but it’s formed up from real numbers from a solid historical database asking trends from the elimination of components.  Not a particularly complex or difficult problem. “When 95% of current wells could not be drilled the impact would be” isn’t real hard to grasp.  Debating over even double digit errors still leaves the economy in a huge disaster.

The geothermal folks better wake up on this too.  Hydraulic fracturing is going to become important in the geothermal field soon.

So I have to ask myself, what are the side effects from stupidal capsules? Sleeping better, better vigor and health, ah, making more money?  There’s a motive in there begging for a journalist’s investigation.  It won’t happen, it’s too incredible to believe to start with, but it is a proposed bill.  Yup, government can make a disaster from nothing at all.  Just pass around some campaign money and stupidal capsules.

Results, stunning, on just one test operation.

USGS Scientist Timothy Collett said, “We have also found gas hydrate in a range of settings, including sand reservoirs, thick sequences of fracture-filling gas hydrates in shales, and potential partially saturated gas hydrates in younger systems. These sites should provide a wealth of opportunities for further study and data collection that should provide significant advances in understanding the nature and development of gas hydrate systems.”

Brenda Pierce, the U.S. Geological Survey Energy Program Coordinator adds, “This is an exciting discovery because for the first time in the U.S. Gulf of Mexico, we were able to predict hydrate accumulations before drilling, and we discovered thick, gas hydrate-saturated sands that actually represent energy targets.”

The important thing to note is that the prediction led to discoveries. That point must not be underestimated. We know there is a lot down there, so knowing where to look is the next step with finding it as expected being a huge time and money saver.

To refresh, gas hydrates, are substances comprised of natural gas and water, thought to exist in great abundance in nature and with the potential to be a significant new energy source to meet future energy needs. It may even be larger than anyone has predicted so far.

Now we know that the U.S. Gulf of Mexico contains very thick and concentrated gas-hydrate-bearing reservoir rocks, which have the potential to produce gas “using current technology.” That’s a new comment within the quotes from the USGS press release. I will get in touch with my Chevron folks to see if they’re backing that comment up, or cautioning more research will be needed and ask for a comment.

Now for some of the more neck twisting, surprising and set one back in the chair numbers. NETL’s Dr. Ray Boswell is saying in the background materials, “This (gas hydrate as an energy resource) potential forms the foundation of the Office of Fossil Energy’s Methane Hydrate R&D Program, which is focused on expanding future energy options by developing the information and technology required for eventual production of natural gas from hydrate.” During the expedition, gas hydrate was found at saturations ranging from 50 percent to more than 90 percent in high-quality sands. The deposits were also found in close accordance with the project’s pre-drill predictions, providing increased confidence in our gas hydrate exploration and appraisal technologies.

Now I take saturation to mean, well, saturation. Commenting at 90% has to be in my view outside of the structure’s sands, shales and rocks. Perhaps that 90% is the share of the gas hydrate to water ratio. It’s not clear and needs cleared up.

What is missing is the permeability and porosity numbers that reveal the voids within the structures that can be filled with the water and gas hydrate mix and the freedom by which the methane from gas hydrates when unfrozen could be moved. Those are the numbers that will give meaning.

Another point in the background is the project featured a number of technical advances, including the use of an advanced suite of logging-while-drilling tools that provided unprecedented three-dimensional images of hydrate-bearing sediments. In addition, the wells drilled at Walker Ridge, approximately 3,500 feet below the seafloor, were more than 1,000 feet deeper than any previous gas hydrate research well.

Gas Hydrate Downhole Exploration Tool. Click image for more.

This bodes well for the future of natural gas supplies. Somewhere, Chevron perhaps, the dill site was identified and when tested with the bit and the instruments proved exciting to say the least.

Others were also involved. Schlumberger provided the initial appraisals of the targets. Borehole Research Group at Lamont-Doherty Earth Observatory of Columbia University is in on it too. I’ve looked for the full list of the group Chevron led with the easy result here.

That confirms the objective of the 21-day expedition that gas hydrate can and does occur at high saturations within reservoir-quality sands in the Gulf of Mexico with highly saturated hydrate-bearing sands discovered in at least in two of three sites drilled. Dr. Collett said, “In addition, we have found gas hydrate in a range of settings, including sand reservoirs, thick sequences of fracture-filling gas hydrates in shales, and potential partially saturated gas hydrates in younger systems. These sites provide a wealth of opportunities for further study and data collection that will enable significant advances in understanding the nature and development of gas hydrate systems.”

The project also featured a number of technical advances, including the use of an advanced suite of logging-while-drilling tools that provided unprecedented three-dimensional images of hydrate-bearing sediments. The wells sited at Walker Ridge, drilled to approximately 3,500 feet below the seafloor, were more than 1,000 feet deeper than any previous gas hydrate research well.

It all looks very good. The puzzle is in the opening line of the USGS Newsroom asserting current technology could lead to production. Just what technology is an intensely interesting answer that may or may not be coming. It could be just a journalist’s slip from the reality or something more noteworthy. We’ll see.

Other than the current technology surprise, the news is quite encouraging. Natural gas is a great product wherever it comes from with all that hydrogen tied up to a single carbon atom in the molecule. Plus methane has great potential as a fuel from giant electrical generation to cars and on to very small fuel cells. Great stuff and a great deal more is good news for consumers.

To solve the problem oil and gas service businesses have invented a rock fracturing technique for deep below the surface. Called fracing for short, the technique quite simply uses raw power to force water, sand and specialized chemical solvents, binders and lubricants into the wells so they open and fill cracks that can allow the natural gas to flow out.

When optimally successful all the fracturing processes have cracks opened and connected to fractures from the next nearby process. In some wells that can get to thousands of meters of opened rock formation. Some oil field guys talk of ‘farming the field.” Times have changed.

In some cases fractures can be done in one well bore as many as 17 times. Modern techniques are used in wells drilled first vertically to the gas rich rock then the well bore tilts over to horizontal. That allow the bore hole to intersect the rock for great distances rather than punch through one lone hole through the rock.

But it’s expensive, drilling starts in the millions per well and runs to close to $10 million expected in the not distant future. Then the fracture work starts which also runs into the millions per well.

But the payoff can be just as good as costs are high. Some wells are producing over 7.5 million cubic feet of gas per day in the first year making the economics attractive if not stunning as last fall in 2008’s pricing. Even after the first year’s flush, such wells can produce 2 million cubic feet per day for years. The next time gas prices take off, the wells will ring like happy old time cash registers.

So how big is one of these projects? In Canada’s British Columbia fields as much as 4.5 million pounds of sand can go down the hole. The water used to move the pressure is powered with some 45,000-horse power of high-pressure pumps. In these fields its common to drill from one drilling site as many as ten wells. That means you need a pretty good road to get there. And getting there takes time as a fraccing can take a week, or 2 ½ months over ten well bores.

In Canada the weather plays a role. A lot of water is involved that must be brought in and moved to each new project. Canada being a cold place, global warming noticeably absent, makes for freezing problems.

To watchers of the oil and gas business the “rig count” or the number or oil drilling rigs working is closely watched each week. But fraccing has multiplied the amount of recovery per well drilled and the rigs that drill horizontally are but a small portion of the total rigs in use. Simple straight down rigs, looking for oil in the U.S. are running primarily based on the cash flows of existing wells and with oil so far down in price, not every rig can be supported to operate.

Last week saw natural gas fall to a six year low. This in an economy that is in recession. But natural gas use hasn’t fallen so dramatically as oil, rather the big home heating market was normal, fertilizer use near a high, electrical generation steady with a consumption fall off in industrial use alone.

We owe an affordable heating season to the oil and gas community for moving on the price signal. It does give considerable credence to the Pickens Plan to move electrical generation to wind and alternatives and use transportable compressible natural gas for transport.

That said, the old barometer of the rig count in North America might be obsolete soon. What’s at issue is the recession and the limits to build more service equipment to do the fraccing work that is piling up. One fracture job can need 20 pumping trucks for a week on a single well bore fracture job. More are needed.

Among with methane hydrates and new biomass sources natural gas has a bright future. There is an existing infrastructure for moving gas; a huge installed base of users and it’s the least contentious fossil carbon fuel. Its pretty good stuff, and the cost to use it isn’t threatened by anyone but the U.S. Congress with its Cap and Trade suicide pact.

There are careers here that will last for decades. Of all the fossil carbon sources natural gas is the least risky for U.S. production of fuels. Oil and particularly coal are in danger with grave consequences in store for consumers as the hysteria over global warming from CO2 continues to drive politics, muckraking and profiteering by its promoters. Even if Congress abandons the common welfare for the perceptions and subversions of special interests, natural gas will be the least affected.

Its good news to temper the bad news from Washington D.C. Ingenuity from the U.S. and Canadian petroleum business is buying time for new technology to come of age and sets a low price for competition assuring that the new technology is real, competitive and sustainable. For all the hate pointed to petroleum, the petroleum market does over long periods serve us well. Very well, indeed.

It will be some time before alternatives can set the low price leadership. There isn’t much that government can do to manipulate that other than to drive natural gas prices higher. In the long view that’s a dreadful error in judgment – delaying or making the race to the lowest cost, equaling to the highest profit supplier unfair, or distorted harms everyone with a gas meter. The effects can last decades.

It’s clear in Europe, where dependency on a major supplier has driven gas to incredible highs. One might think that the North American market would be smarter. It is – left alone. That’s the bad news, its not being left alone, which leavens the lowest price seen in six years with concern for the future not the fuel, but the government.

Known as gas hydrate, it is a frozen form of natural gas that can burst into flame at the touch of a match and show increasing promise as abundant, untapped sources of clean, sustainable energy. Those icy chunks could supplement traditional conventional natural gas sources that will become more expensive, perhaps in short supply and are being used to substitute for coal in electrical power generation and increasingly to fuel cars.

Ignited Gas Hydrate. Click image for more.

Science has known about gas hydrates for decades, but only recently the last decade has seen well-funded efforts to use them as an alternative energy source. Gas hydrates are also known as “clathrates,” that form when methane gas from the decomposition of organic material comes into contact with water at low temperature and high pressure. Those cold, high-pressure conditions exist deep below the oceans and underground on land in certain parts of the world, including the ocean floor and permafrost areas of the Arctic.

The volume that can actually be produced on an industrial scale depends on the ability of scientists to extract the methane from gas hydrate formations in an efficient and cost-effective manner. Scientists worldwide are now doing research on gas hydrates in order to understand how this strange material forms and how it might be extracted to supplement coal, oil, and traditional natural gas.

Last November, a team of USGS researchers announced a giant step toward the future. In a landmark study, the USGS scientists estimated that 85.4 trillion cubic feet of natural gas could potentially be extracted from gas hydrates in Alaska’s North Slope region alone, enough “to heat more than 100 million average homes for more than a decade.”

Study co-leaders Tim Collett, Ph.D., a research geologist with the U.S. Geological Survey in Denver, and Ray Boswell, Ph.D. who manages the National Methane Hydrate R&D Program of the U.S. Department of Energy’s National Energy Technology Laboratory in Morgantown, W. Va. suggest that one of the more promising techniques for extracting methane from hydrates involves simply depressurizing the deposits, Boswell says another suggested method involves exchanging the methane molecules in the “clathrate” structure with carbon dioxide. Workers can, in theory, collect the gas using the same drilling technology used for conventional oil and gas drilling.

Scientists are particularly optimistic about the vast stores of gas hydrates located in Alaska and in the Gulf of Mexico. The Methane Hydrate Research and Development Act of 2000 has funded collaboration with universities and private companies, to investigate gas hydrates as an alternative energy source. With several millions dollars already spent, research is accelerating under the U.S. Department of Energy and USGS to better understand gas hydrate’s role in the natural environment and in climate change. One might hope most of the money is going to extraction research.

Tim Collett says, “Gas hydrates are totally doable, but when and where we will see them depends on need, motivation, and our supply of other energy resources. In the next five to ten years, the research potential of gas hydrates will be more fully realized.” Ray Boswell offers, “Once we have learned better how to find the most promising gas hydrate deposits, we will need to know how to produce it in a safe and commercially viable way. Chemistry will be a big part of understanding just how the hydrates will respond to various production methods.”

Locating the gas hydrate is an ongoing effort with only the north slope of Alaska having a study with decent data for estimates. The Gulf of Mexico also has vast reserves of methane locked up in gas hydrates and more is known to be off the east U.S. coast. Other countries are looking too, with Japan and India discovering huge stores of methane and are leading research with well-funded gas hydrate research programs.

The American Chemical Society press release about the gas hydrate presentations also includes:

• E. Dendy Sloan, Ph.D., of the Colorado School of Mines, who provided an overview of this rapidly evolving field. He is the author over 200 publications, including the third edition of “Clathrate Hydrates of Natural Gases,” co-authored by Carolyn Koh.His presentation provides overview of gas hydrates for energy production and climate change where some scientists predict that natural gas hydrates will play a major role in both energy and climate change in the future.
• Masanori Kurihara, Ph.D., of Japan Oil Engineering Co., Ltd., described Japan’s National Methane Hydrate Exploitation Program, including research on promising methane hydrate deposits in the Eastern Nankai Trough of offshore Japan.Japan has one of the world’s largest and most promising national gas hydrate research programs and is well on its way toward using these hydrates as an important fuel source.
• Scott R. Dallimore, of Geological Survey of Canada, will provide an overview of the country’s contributions toward gas hydrate production.Canada has a huge reserve and likely the longest effort in research being involved in gas hydrates research since the 1970s and now plays a leading role in hydrate production technology.

The puzzle remains extracting the methane out from a very cold, wet and high-pressure zones both under water and deep underground. Its known in the oil and gas business that the potential is there, but the technology isn’t firmed up or understood in the economic costs to free the methane.

Which is not to say that there isn’t a price at which has hydrate resources become viable. The issue for consumers is what the price might be. The natural gas market is under pressure worldwide more so than U.S. consumers recognize with what U.S. consumers would regard as shockingly high prices. Major efforts are under way to liquefy natural gas and move it to locations where demand will support the costs to find, develop, liquefy, ship, re-gasify and transport to users. It’s an expensive series of steps, but in some parts of the world, simply necessary.

With those broad strokes of the world market in mind extracting methane from gas hydrates seems more important than a U.S. consumer might realize. But liquefying natural gas is coming to the U.S. market over the coming years, which is certain to bring more demand to the natural gas pricing structure.

More reserves – even gas hydrates is welcome – but producing them needs much more investment and innovation.