For Canada and the U.S. the oil boom is in the field called the Bakken, a widely spread oil reservoir with top quality oil trapped in a difficult rock right in the center of the North American continent.

Bakken Formation in the Williston Basin. Click image for the largest view.

Geologist JW Nordquist discovered the Bakken in 1953. He described it as an “Oreo cookie” arrangement of hard dolomite rock sandwiched between two darker shale layers.  For decades, petroleum geologists thought the Bakken shale was the source of the oil pools in the wider Williston Basin. But in 1999, Leigh Price, a geochemist working for the US Geological Survey (USGS), wrote a paper proposing that most of the oil from Bakken shale was still trapped in the Bakken Formation. He suggested the “cream” in the Nordquist Oreo cookie contained up to 500 billion barrels of crude, making it a prime exploration target. It is the dolomite “filling” that contains the oil causing all the excitement today, although that oil may have formed in the surrounding shale.  Mr. Price died in 2002, before his paper was published. The USGS was skeptical and for years refused to release the report and their review of it.

Meanwhile, an independent petroleum geologist, Richard Findley, reviewed drilling logs from abandoned Bakken wells and concluded that the operators missed the pay zone by drilling right through the hard oil bearing rock between the two shale layers. He interested Lyco Energy, based in Texas, in his theory.  Lyco brought in the services company Halliburton to try out what were then developing technologies: horizontal drilling; and hydraulic fracturing.

Findley, Lyco and Halliburton discovered and developed the Elm Coulee oilfield of eastern Montana in 1997.  The Elm Coulee oilfield now pumps about 50,000 barrels per day of light, sweet crude and is considered a small part of the larger Bakken field.

Non-USGS geochemist and geologist research has largely vindicated Mr. Price.  Non-government estimates of Bakken oil in place have ranged from 10 billion to 500 billion barrels. The most recent, built with sophisticated computer modeling, suggests 300 billion to 400 billion barrels could be realistic.  Every new well fills in the gaps making the later estimates stronger bases for more investments.

By 2008 in an effort to catch up, the USGS estimated that about 4 billion barrels of oil could theoretically be produced from the US part of the Bakken with current technology It represents enough oil to satisfy US consumers for about six months – hardly a game-changer.

Technology is advancing, so actual oil recovery could vastly exceed initial estimates and the Bakken is still a very young field with little development.

Canada’s Crescent Point Energy has tested a fracturing and water-flood recovery technique that boosts recovery from wells in Saskatchewan to 30 per cent of oil in place. “These mainly untapped resource pools provide Crescent Point with over 5,000 drilling locations and the potential to add over 500 million barrels of reserves,” Scott Saxberg, the company’s president and chief executive, told the Calgary Herald newspaper. “It’s unique that it’s light oil, and in our back yard, and it’s low cost,” he told Canada’s National Post.

Production form the Bakken is relatively economical as well. Costs for producing oil from the relatively shallow wells required to tap Bakken oil pools have fallen to about $5 per barrel, compared with tens of dollars per barrel for extracting tar-like bitumen from Canada’s oil sands and chemically converting it into synthetic light crude.  As a measure of the confidence major investments are underway the Canadian pipeline development company Enbridge is expanding their network to accommodate more oil from the Williston Basin.

The U.S. portion is described as the country’s largest oil deposit outside Alaska, and its biggest and most accessible part is in Canada. The Bakken could prove to be one of the largest oilfields in the world.  The American Association of Petroleum Geologists says it is the biggest continuous oil accumulation it has ever assessed.

In a reality check, since Drake’s first well over 150 years ago the hunt has been for wells the flow under their own pressure leading to the gushers then followed by pumping.  The hunt goes on today as seen in the BP blow out fiasco in the Gulf of Mexico.

But most any oil basin is going to have oil formations that are not gushers, with huge amounts of more difficult to recover oil.  The list is just being looked at now.  The Bakken may be big, but it’s actually the first of what is likely to be more to come.

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.

Shale oil has high levels of nitrogen, sulfur, and unsaturated hydrocarbons, limiting its potential use to supplant or replace crude oil.  Coming up with economical cleaning systems would get shale oil more competitive.

There is a lot of shale oil out there. Using a the Fischer Assay, which yields a heating value, across the planet’s known reserves turns up numbers like 3.3 billion tons with 2.8 billion, more than 78% in the U.S.  Most of that is in the Green River Formation out in Colorado.  It’s a huge reserve.  No other known reserve exceeds 20% of the Green River deposit and most come in under 10%.  Not that those others are small, the Green River deposit very conservatively holds more than 200 years of U.S. needs at current use rates.

Close-up of fractured oil shale specimen from the Uinta Basin, Utah, showing weathered (white) and unweathered (black) surfaces. Photo courtesy of Argonne National Laboratory.

The first problem is that shale oil is actually kerogen.   Kerogen is a mixture of organic chemical compounds with the soluble portion is known as bitumen, the stuff of the Canadian Oil Sands.  Not all of the organic chemicals come up as bitumen.  The problem is what’s missing – hydrogen.  Kerogen is carbon rich, but hydrogen poor.

Extraction then is quite costly and energy intensive.  Heat is needed to raise the viscosity and the heat would be applied to the rock that contains the kerogen.  Lots of heat is needed.  Then the kerogen needs refined and cleaned.  Adding solvents or adding back hydrogen can improve the oil product results.

Some processing methods yield considerably more useful product than the Fischer Assay would indicate. The Tosco II method yields over 100% more oil, and the Hytort process yields between 300% to 400% more oil.  There could be an enormous supply of petroleum products if the extraction, hydrogen enrichment and cleaning problems get solved.  All it takes is ingenuity and money in a high enough crude oil price environment to get investment on board.

The use of shale oil remains a puzzle.  Like Canada’s Oil Sands, kerogen from oil shale could be either dug up or extracted in place as in “in situ” processes.   Cheap hydrogen and low cost cleaning also need solutions.  Petroleum isn’t in short supply, easy to extract, refine and clean petroleum is, though.

So when the Chinese paper appeared in the American Chemical Society journal Energy & Fuels a certain acclaim is due.  From the abstract:

Because of high contents of nitrogen, sulfur, and unsaturated hydrocarbons in shale oil, its potential use as a substitute fuel is limited. In this paper, catalytic hydrotreating of the diesel fraction (200−360 °C) from Fushun shale oil was preliminarily investigated in a fixed-bed reactor. Hydrotreating experiments were carried out using various available commercial catalysts, including CoMo/Al2O3, NiW/Al2O3, and NiMoW/Al2O3, at different conditions of temperature, hydrogen pressure, liquid hourly space velocity (LHSV), and ratio of hydrogen/feedstock. The results showed that the NiMoW catalyst was most active for heteroatom removal, in comparison to other catalysts. Under relative mild conditions, it was possible to produce clean diesel from a Fushun shale oil distillate. The produced oil had low contents of sulfur, nitrogen, and alkene, reduced density, and increased cetane number, and it could be used as a more valuable fuel.

There’s a piece of the puzzle on the cleaning side.  Just how clean or clean enough isn’t yet clear.  China doesn’t give much care to CO² or other environmental matters. But the knowhow is now out on the catalyst discovery.

Numbers passed around have U.S. shale oil worthwhile at perhaps as low as $35 a barrel, a number that challenges the imagination. Canada’s Oil Sands gets into financial trouble as oil prices get close to $50 so its a sure bet that the kerogen to bitumen step is going push it higher.  But the reserves in shale are getting closer to market.  Big breaks in technology will only help.

But the hard price of crude oil isn’t there yet.  Today’s mid $70’s is a function of OPEC limiting the market.  Just what a barrel of oil is worth is something less than that.  The conditions for billions of investment aren’t ripe yet.

The technology is closer.  But the politics further.  There is considerable doubt that the world’s largest reserve will ever get to market as politics stand in the way.  The leftist politicians are betting technology and public opinion will get petroleum out of the energy market.  Keep in mind, they bet with your life – if they lose you lose.

From the most hydrogen rich petroleum, natural gas, to lesser hydrogen rich crude oil, heavy crude oil, bitumen, kerogen all the way to hard anthracite coal there are stunning amounts of carbon-based fuels around.  The biosphere is busily recycling carbon through plants attaching hydrogen back and releasing oxygen for us to breath.

The question for the thoughtful is, can the human species control itself such that the carbon cycle can keep up?  The answer is an obvious, yes, with energy inputs from solar, geothermal and nuclear fission and fusion – a happy carbon cycle is possible supporting a large human population and the plants and animals of the world.

Oil shale could have a role, soon if the technology develops at a good pace and politics pays attention to its responsibilities instead of its idealisms.

Dr. Larter was the keynote speaker June 17 for the 2010 Goldschmidt Conference hosted by the University of Tennessee, Knoxville, and Oak Ridge National Laboratory.  In his presentation, “Can Studies of Petroleum Biodegradation Help Fossil Fuel Carbon Management,” Larter discussed microbes in the environment and their role in breaking down oil and generating natural gas.

This is with an eye to the feasibility of recovering hydrogen, instead of oil, directly from oilfields undergoing natural biodegradation processes.  Larter is also examining the feasibility of using a related process, biologically assisted carbon capture and conversion of CO² to methane or natural gas via H² + CO² methanogenesis in the hydrogen-rich environments of weathering subsurface ultrabasic rocks, as a route to recycle carbon dioxide in flue gases back to methane.

In Situ CH4 Production Process Diagram. Click image for more info.

But the most interesting is the in field conversion of oil to natural gas.  If Larter can develop the idea into a working process much of the oil in place, or about 4 times the oil already pumped and used could be available in the form of natural gas.  It’s an astonishing concept.

Over two years ago Dr. Larter showed how crude oil in some oil deposits around the world — including in Alberta’s oil sands — are naturally broken down by microbes in the reservoir.  Larter is working on understanding how crude oil biodegrades into methane, or natural gas, opening the door to being able to recover the clean-burning methane directly from deeply buried, or in situ, oil sands deposits.

Currently a problem exists out of the media and public’s view – biodegradation of crude oil into heavy oil in petroleum reservoirs is a problem worldwide for the petroleum industry. The natural process is caused by bacteria that consume the oil, making the oil viscous, or thick, and contaminates it with pollutants such as sulfur. This makes recovering and refining heavy oil difficult and costly.  People don’t realize they’re competing with microbes for the oil.

Using a combination of microbiological studies, laboratory experiments and oilfield case studies, the University of Calgary team demonstrated the anaerobic degradation of hydrocarbons to produce methane. The findings offer the potential of ‘feeding’ the microbes and rapidly accelerating the breaking down of the oil into methane.

Larter is now working on an approach of capturing carbon dioxide and pumping it and special bacteria underground into alkaline rock formations where the carbon dioxide, a greenhouse gas, will be converted into natural gas.

Larter says the petroleum industry already has expressed interest in trying to accelerate biodegradation in a reservoir.

The business end has already started with Dr. Larter involved with Gushor, a Canadian consulting firm.  Gushor is focusing on heavy oil recovery, fluid mobility, biodegradation, and carbon management emissions.

To date Larter’s findings indicate that feeding the oil reservoir microbes rapidly accelerates the breaking down of oil into natural gas.  Larter says, “Instead of 10 million years, we want to do it 10 years. We think it’s possible. We can do it in the laboratory. The question is: can we do it in a reservoir?”

The matter now is the sense of urgency.  With ‘peak oil’ losing its public momentum, a great U.S. success from the Bakken formation in the Williston basin, a major oil well disaster in discovering a huge field in the Gulf of Mexico, and a series of discovery successes over the past two years around the world, the recovery techniques that Larter is proposing are getting pushed back into the less urgent category.

That might not be the best idea.  Petroleum hydrocarbons will be needed for centuries in declining amounts.  Natural gas isn’t particularly good as a motor fuel, but would certainly be useful for light transport substitution. But for making heat whether for a home on to producing steam, natural gas is a very desirable product.

The clean motive – less CO² also has a friend in natural gas.  The single carbon atom in methane (CH4) with the four-atom hydrogen set makes for a lot of heat for a minimum of carbon reaction with oxygen.  Methane also could have a big role in high efficiency fuel cells.

Larter’s work is getting noticed and consideration.  The move to commercial interest is underway.  It’s an idea well worth having in the world’s fuel production arsenal.

It’s worthy news.  This writer hasn’t addressed the BP gulf floor leak – you’ve noticed, and maybe won’t at all.  It’s simply a media frenzy and political positioning structure while the people and environment take the hit.  Blaming and leveling responsibility takes precedence over imparting resources, something the big oil industry has to do alone while coping with the public relations cost of stupid media and useless political power.  Enough for now – but that’s an idea of why the post hasn’t been written.

Scott Saxberg, chief executive of Crescent Point Energy Corp. told the company’s annual general meeting the application of water flooding, along with infill drilling, could allow the company to more than double reserves within five years.

Water Flooding Oil Reservior - A Simple Example. Click image for the largest view.

In an interview, Saxberg said two years of tests at an initial pilot project in the Bakken – and more recent results from a second test – show that injecting water into formations being tapped by nearby horizontal wells with multiple fracture stimulations can help boost recovery from about 10 per cent to 30 per cent of oil in place.

For Crescent that would mean, “These mainly untapped resource pools provide Crescent Point with over 5,000 drilling locations and the potential to add over 500 million barrels of reserves, which could potentially double our current net asset value,” Saxberg said.

Saxberg explains, “We’ve seen very strong results. What it’s done in the pilot over the past two years is give us flat production. Without it, it’s 10 per cent, and with infill drilling you might get to 20 per cent. And then with water flood it’s 30 per cent. That’s huge.”

It’s because normally, after an initial “flush” of production in the first year, Bakken oil output drops off by about 70 per cent.

But Analyst Kyle Preston of Canaccord Adams cautioned that Crescent Point’s water flood strategy is promising, but not necessarily proven in all areas of the Bakken saying, “This water flood technology is not really new. What’s new here is applying the water flood to a tight rock reservoir which, to my understanding, hasn’t been done very successfully in the past.”  Preston points out PetroBakken, the second-largest player in the Bakken, doesn’t believe in water flooding.

Here’s a look at how Canada treats new resource development.   Trent Stangl, Crescent Point’s vice-president of investor relations, explained the company’s strategy is to let a central well produce for about a year to take advantage of Saskatchewan’s royalty holiday on new horizontal wells before converting it into an injector well. Then forcing water into the well builds pressure underground to push more oil out of surrounding wells, a technique commonly used in conventional oil fields.

Saxberg adds, the company is also experimenting with cemented liners on the horizontal part of the wells instead of steel pipe, allowing adjustments in the number of fractures as the well ages. He added the company is pleased to hear about the Alberta government’s new royalty incentive plans, including lower royalties for deep wells and horizontal wells, but he has no immediate plans to spend money in Alberta.

We’ll see how long that lasts in Alberta.  One nation’s dumb move can be another’s windfall.  As the U.S. administration plays media politics and undermines the national economy the neighbors, bless ‘em, can make good use of the capital.  And why not?  Our Canadian neighbors can use the capital, jobs and economic growth as well or better than anyone else.

The only concern then is, can the Canadian effort stay profitable at lower oil prices?  With the Athabasca oil sands under political assault the Alberta and Saskatchewan provinces need a fall back.  The irresponsible and capricious political neighbor brings risks, as the U.S. economic recovery isn’t driving lots of oil consumption.

Crescent Point plans four more pilot projects throughout the Bakken field over the next year.  With U.S. offshore drilling at a standstill, the capital going inert, worker layoffs imminent, and a sure increase impact on the world price of oil, the BP leak looks to grow far beyond a single company’s disaster and ecological calamity.

Irresponsible and capricious political conduct might be media savy – but the impact will be long and costly for consumers the world over.  But hey, only about 75% of American’s are catching on – throwing in with BP to get the oil escaping contained, stopped and the ecology and economy protected, sustained and supported could have been the job.  But leftism doesn’t even think to cooperate with business. Leftism needs commercial disasters to participate in the economy.  Commercial disaster gone far enough is an ‘opportunity’ to bail something out and take over making the capital, jobs and eventually, the management their own.

The Bakken oil field and the Canadian firms leading the technology are refreshing in the current U.S. situation.  Thanks neighbors, we wish you well.  Thanks to the Calgary Herald for kicking up the story. Americans need a little good oil news about now.

Eagle Ford Trend Map. Click image for more info.

It’s the liquids that have so many noticing.  Methane and some ethane are the principle components of natural gas.  Ethane is usually taken out in part or wholly removed to use in chemical processes.  They are both gasses at reasonable pressures.  The ‘liquids’ start with propane, a liquid at comfortable, low technology pressures.  A three carbon atom petroleum molecule at moderate pressure is liquid, thus the name ‘Liquid Petroleum Gas” or LPG.

Propane is often made by fracturing larger petroleum molecules from oil products.  That’s the key, the liquids starting with propane are much more expensive than the natural gas products and command better prices.  The four carbon atom butane common in pocket lighters, five carbon atom pentane, six carbon atom hexane and the seven carbon atom heptane all have large well developed markets.  At the five carbon atom molecule to seven, the liquids stay that way at atmospheric pressure, even though they vaporize rapidly, are called natural gas condensate or sometimes called natural gasoline or simply as condensate.   Flowing directly from the well instead of having to be refined out or made from oil makes these products valuable.

With natural gas prices way down and cheap compared to oil, sometimes as low as 1/20th as much per Btu as crude oil, the expensive well drilling and completion technologies have a new way to stay busy and support energy supplies.  It’s difficult to imagine a better time than now for the Eagle Ford and the Granite Wash areas to be rediscovered.

Eagle Ford is proving to be rich in condensate. More information about the size of the field and the volumes of condensate and gas is coming out almost every day now, and the numbers are getting better and better. Only a year ago a dozen drilling rigs were working across the entire area that stretches across more than 30 Texas counties. Today, more than 50 rigs are drilling well after well.

Those 50 drilling rigs should allow production to grow to nearly 40,000 barrels of oil equivalent per day within the next 24 months. That’s roughly $1 billion worth of oil per year at current prices. Keep in mind; this is just from the handful of rigs working in Eagle Ford during 2009. The estimates don’t include the value of the natural gas that will also be produced.

New seismic technologies are being employed to find liquid hydrocarbons, even though the wells are deep and the productive regions narrow.  Eagle Ford wells are drilled about 12,000 feet down and Granite Wash starts at 13,000 on to 17,000 feet, with the productive zone usually only a few hundred feet thick. To efficiently drill these wells requires horizontal drilling, where rigs first must bore down to the oilfield and then veer sideways through it.

The combination of these new technologies is releasing huge amounts of liquid hydrocarbons in the Eagle Ford and newly active Granite Wash area in North Texas.

Granite Wash Well Intensity Map. Click image for more info.

Penn Virginia, a U.S. publicly traded exploration firm disclosed during its first quarter operational update that it has drilled 18 gross wells so far in the Granite Wash. Its average initial production rate is 10.1 MMcfe per day, and it has reduced its well cost to $6.3 million each.

The Granite Wash area spans 2,000 square miles across parts of the Texas Panhandle and western Oklahoma.  Some of the Granite Wash wells drilled thus far have shown up to a 30%-plus liquids component of the production stream, which at current crude prices makes for significantly improved economics.  The Granite Wash area is very low risk due to substantial sub-surface information, efficient to market because significant transportation and services infrastructure already exist in the area.

Granite Wash is a significant boon to North Texas.  As big as it is, its tiny compared to Eagle Ford.

The Eagle Ford shale trends across a great swath of Texas, stretching from the Giddings Field in Brazos and Grimes counties down southwest into the Maverick Basin in Maverick County at the border with Mexico.  The field is huge. The Eagle Ford was formed during the Cretaceous period has long been known as a “majestic source rock”, meaning the petroleum has been seeping up into easier to access zones supplying hydrocarbons to the great Austin Chalk fields and the famed giant East Texas Field for tens of millions of years.

Now it’s becoming productive as an impressive self-sourced reservoir.

Some folks are already calling the Eagle Ford area the sixth largest domestic oil discovery in U.S. history. The shale found there has higher natural porosity and permeability than other shale formations.

It used to be a problem when drilling through it for deeper oil.
The Eagle Ford has another interesting aspect.  Its been drilled through aplenty with well bores available that could possibly be re-entered and drilled horizontally at much reduced cost.

In one news release a well was drilled to 11,300 feet with a horizontal lateral over 3200 feet. The operator managed to pack over two million pounds of sand in ten stages. The Eagle Ford shale is high in carbonate content, making it very brittle and therefore able to be easily hydraulically fractured.  Its little wonder the field is prolific.

The infrastructure is already there, too.

While not every well that’s drilled will be productive, in shale exploration like this one the odds are much better.  Unlike the relatively small fields and pockets of oil and gas that exploration companies have chased over the years, this field is huge, underneath a very wide swath of Texas, all the way from Southeast Texas to Mexico. The mainstream media has not yet reported the full implications of this massive oil and gas field, but it will be major news very soon.

This is good for Texas and all of the U.S.

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.

Kosakewich’s firm Triple D Technologies uses the premise to ‘Frack,’ the process to fracture petroleum bearing rock downhole.  Similar to the freeze-thaw process that creates frost heaves in winter, the patented system freezes formation water deep in the well, causing it to expand and crack the rock, opening up new passageways for hydrocarbons to flow into the wellbore. Kosakewich says, “After all, ice moves mountains, doesn’t it?  It certainly does.

Ice formation has tremendous power, which through its freeze-thaw cycles can destroy roads, bridges and buildings, can also help boost oil and gas production.  The process should also be much less violent; in a water pressure fracture pressure builds until something gives way, which can generate a shock wave, sometimes quite noticeable at the surface of the ground.

Water gains about nine per cent in volume when it turns to ice. Sent down well bore holes and frozen the resulting power exerted on the surrounding rock is three times stronger than the pressures created by today’s fracturing — “fracking” — when well service companies split rock to release oil and gas in tight formations.  Ice acts in all directions, so the freezing also creates radial fracturing – and the magical thing called vertical ‘fracs’, which stay open after the water is removed,” Kosakewich says this removes the need for sand or other materials to prop open the cracks.  It might be the freezing cycles just make  sand from the formation rock as seen in concrete freezing destruction.

Repeating the freeze-thaw cycles over many hours also creates a  “jacking” effect, with the cracks running farther and farther out from the well bore, much like a crack in a car windshield gets longer with each heating and cooling cycle.

Kosakewich believes “This technology is a game-changer, and allows the small and medium-sized firms a chance to compete with the big firms, which are publicly traded and can raise a lot of money.”  A plan to be tried in a mature oilfield in the Pembina reservoir, will be to rework the depleted areas, with the help of PetroJet, a Calgary company that uses revolutionary fluid-cutting technology to auger through installed well casings and create new horizontal bore holes.  “They can go 50 meters out from the existing vertical bore in four directions, and we can frac in all these directions. Even if we can recover only three to five per cent more oil from these fields, that represents an incredible reserve of light, sweet oil from existing fields, and with all the infrastructure in place,” Kosakewich said

Kosakewich contracted with Pace Industrial four years ago to design and test down-hole refrigeration technology. Technicoil, a coil drilling service firm, provides the method of delivering the refrigerant, liquid carbon dioxide down the borehole. “We simply pull out the (pipe) string and install our own, a concentric coil like a car’s power aerial. This all works like your home freezer,” said Kosakewich.

Freeze Frack Wellhead Operations. Click image for more info.

Liquid CO2 still flows under pressure at minus 55 C.  It’s pumped down a small inner pipe. The liquid CO2 flows back to fill the space between the inner pipe and the almost three-inch outer tube. Water is pumped down to fill the space between the outer tube and the eight-inch borehole.  The water is slowly frozen – expanding and cracking the surrounding rock.  The high pressures inside the refrigerant pipe protect it from damage.

Freeze Frack Fracturing Process Diagram. Click image for more info.

Kosakewich said his frac method simply requires a truck of liquid CO2, and coil and pumping equipment compared to the commercial fracking today that typically requires powerful and expensive equipment, and dozens of truckloads of water.

Kosakewich says, “None of this technology is new. But the concept is new, and sure to upset the way business is done in the oilpatch.”  Best of all, its low cost means small firms get a chance to get into well fracturing and there are hundreds of thousands of wells thought to be depleted that may be restored to production with this innovation, just the thing for giant growth across much of the old oil producing areas.  Think jobs, lots of jobs.

It’s one of the grandest innovations this writer has seen.  The properties of freezing that northerners can see every winter developed for fracturing rock offers a very different scenario than high pressure water.  Yet some whiz is going to combine the two – a certainty – from which oil and gas production is certain to increase.  The slow expansion of ice, bearing directly on the rock its in contact with, will yield very different results in opening fissures for petroleum products to flow.  Water is much more dynamic, it will crack into the least resistance, flow and crack into the next least resistance, and so forth until the budget is used up.

Kosakewich’s technology should also take the fear away, the slower process is likely more a crushing event than cracking, reducing the shocks, the shaking, the chance that a fissure would point to the surface and allow much closer operations to where people live and work.
Freeze fracturing won’t work everywhere, some rock won’t cooperate, some reservoirs are going to be to hot and other challenges will bar the way.  Yet the total of old “easy” oil and gas that could be accessed again – is stunning.

Let’s encourage Kosakewich and his people – congratulations are in order, this is a technology begging for many minds to continue the innovations.  Its one more step to 100% reservoir recovery – which could dramatically increase the petroleum reserves available worldwide.  And jobs, good jobs, good paying jobs!

Meanwhile, for all the U.S. political left’s glorious attempts to remake the facts, the nearly trillion-dollar ‘stimulus’ plan passed nearly a year ago is a dismal failure.  The money spent is gone, the remaining is who knows where to be spent who knows how.  At such heights of budget commitments, Americans should expect better, especially as the money is being borrowed by the government to be paid back by today’s kids in their adulthood.

The Keystone pipeline, a TransCanada project, is going to go through some $12US billion by the end of 2010 with most of it spent in 2009 with just less than half spent in Canada and a little more than half spent in the U.S.   It’s one of the reasons the states the line goes through aren’t in such desperate shape.  The system also has significant impacts across other industries.  The main component, steel for the tubing, has kept the U.S. steel industry off the floor right through the worse of the nation’s recession.  One usually expects steel to be on the front line in recessions, and this time, thanks to oil development, missed the deepest part of the economic dip.

Keystone Pipeline Route Map. Click image for the largest view.

The project will see initial nominal capacity of 435,000 barrels per day, which will be expanded to 590,000 barrels per day in the first quarter of 2011. Keystone ships heavy crude oil to the U.S. Midwest markets and ultimately will get the crude oil to the Gulf Coast through an expansion and extension called Keystone XL, where refineries are better equipped to handle heavier crude.

Keystone XL, another 1,900-miles of 36-inch pipeline extension and expansion, would increase the capacity to 1.09 million barrels per day from Hardisty to Port Arthur, Texas, and other U.S. Midwest markets, with in-service expected in the fourth quarter of 2012 or early 2013. The pipeline system is further expandable to 1.5 million barrels per day at relatively low cost, enhancing future growth opportunities.

Keystone solidifies the central U.S. crude market and also is an asset to get the oil production growth out to markets.  For those consumers, the Keystone project is an oil safety net filled with North American production.  It should make consumers on the coasts a little envious.

The Alberta Clipper, an Enbridge project, consists of a 36-inch diameter pipeline, and associated pumping and terminal facilities, from Hardisty, Alberta to Superior, Wisconsin.  The initial capacity of the line will be 450,000 barrels per day of heavy crude, expandable at very low cost, through the addition of pumping facilities, to 800,000 barrels per day.

Alberta Clipper Crude Pipeline Route. Click image for the largest view.

The 1,000-mile segment is designed to resolve expected capacity constraints and is expected to be in service by mid-2010, complementing the recently completed Southern Access Project as crude oil supplies from Western Canada continue to increase.  With supply from Western Canada oil sands developments expected to grow by as much as 1.8 million barrels per day by 2015, the industry has asked for more pipeline capacity out of the oil sands into the U.S. Midwest markets. The request is driven by oil sands producers and refiners that have long development timelines and need assurance that adequate pipeline infrastructure will be put in place in time to serve their projects.

The line will officially go into service in mid-2010 after the U.S. portion of the pipeline is complete.

Enbridge is also setting up expansion and extensions beyond the Minnesota leg to Superior Wisconsin.  Enbridge is planning to extend the system from its Flanagan terminal south to the petroleum transportation hub in Patoka Illinois.  The expansion runs from Superior Wisconsin to Flanagan Illinois.  Flanagon is becoming a major oil hub.  Just driving down Interstate 80 west of Joliet Illinois on can see the refineries in the distance.

Enbridge Extensions to Alberta Clipper. Click image for the largest view.

The TransCanada and Enbridge projects employ thousands of people across a wide range of contractors. The multiplier on the spending should compare or exceed the stimulus of government projects on a dollar basis.  But the economic impact is being overlooked – the government policy and spending make more interesting news for the media.  Right down the center of the continent is stimulus; a result from the run up in oil prices that for some is a job, others surety of supplies, and for everyone a healthier economy.

One wonders, with the increased production from Canada oil sands and the Bakken formation across North Dakota and Montana getting rolled into new projects just how much ‘stimulus’ is taking place and the multiplier effect.  One thing is for certain; this stimulus is paying off right now, and will continue to benefit the Canadian and U.S. economies for decades to come.  Compare that to the near trillion-dollar boondoggle Congress is spending.

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.