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

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

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

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

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

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

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

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

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

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

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

Its looks like a game-changer, indeed.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

It’s no surprise that the technology is already international, starting in the U.S. its already going to work in Canada, Argentina, Russia, Mexico, Poland, the Middle East and more.

The leaders of the new boom that can be expected over time to be used in millions of wells worldwide are the major petroleum service companies, Halliburton, Schlumberger and Baker Hughes.

The “super fracking” as its becoming named is based on three basic improvements.  The first is Schlumberger’s “HIWAY” idea that is an innovation in the material forced into the rock. (The linked page has a good animation to explain the process in detail.)  The new idea is to add fibers to the mix of hard small grains used to hold open the cracks.  The fiber is being seen as a major production improver.  Much more flow for a longer period is the result. That flow, called conductivity, has been the problem of wildcatters for 150 years.  The petroleum is there, but it won’t come out.  How much more the fiber offers has investors in oil reserves pouring over 100+ years of history.

Schlumberger's Flow-Channel Fracturing Illustrated

The second idea called “RapidFrac” comes from Halliburton with a set of highly developed specialized pipe fittings that go into a newly drill hole.  (This page also has a high quality animated video, though quite a large file.) Much like valves, these sections of the pipe when activated open passages to the rock.  With two types, a set of one type in a row can be used to work a section to specifications learned from the drilling results and geophysics.  The second type then is an isolator to keep the work specific to the set before moving on to the next set.  It’s a very sophisticated means to crack a vast volume of petroleum reserve rock.

Halliburtons RapidFrac System Illustrated. The explanation is part of the jpg, click the image to see the largest view.

Halliburton’s new technology also has a second benefit, the accurate and limited groups require about half the water and much less time.  Where time is money this level of conservation and efficiency really adds up.  It also should cut back on the fears – stuffing half as much water down is going to reduce the amount of risk – and the targeted zones will be much easier to study.  For the local folks it means half the traffic per job, too.

The fracking business is made up of the two huge companies and a veritable army of others making well completion a very competitive business.

The pipe placed down a well is getting more sophisticated, and the valve idea isn’t unique to Halliburton.  The current technology is sending balls down the pipe that stop where the diameter is too small. Of late the balls dropped in are made of plastic that can be drilled out when the frack pressure work is done.  The third idea is Baker Hughes has developed disintegrating frack balls (No company info yet.).  This solves the need to have a drilling rig return to the well, and spend several days drilling and fishing out the perhaps a many as 20 or even 30 balls dropped in to do the frack in stages.

The controlled “explosive” (its more of a really fast burn) blast technology to get through the pipe and into the rock isn’t laying about – here Baker Hughes has a fourth idea, developing and testing “super cracks,” a method of blasting deeper into dense rock to create wider channels in order to funnel more oil and gas. The aim for the technology, branded “DirectConnect,”(pdf file link)  is to concentrate fracking power to target oil or gas buried deeper in the formation.

Baker Hughes FracPoint MP sleeve with DirectConnect ports Illustrated. Use the brochure link for a more complete explanation. Click image for a larger view.

Perhaps the best news is the new technologies are reducing costs in a big way. Investor stock trackers have noticed and estimates like the one from JPMorgan Chase projects drops from $2.5 million per well down to an astonishing $750,000 – a drop of 70% – money that will get reinvested in more drilling and production.

Many are surprised at the massive gains in the U.S. production of petroleum, with finished products making the U.S. a net exporter again.  The innovation, daring, risk assumption, testing and prices for oil have gotten the door open and the oil bidness has pressed right on through with American ingenuity and character.  The new technologies will soon be major U.S. exports – cutting back on the world’s marginal last barrel risk and suppressing prices back to reason.

A year of high prices and past years of wild swings in oil prices may seem a trauma, but the industries’ reaction to the trauma has made the supply much more secure for a longer time.

With one hundred and fifty years of buildup the petroleum business has only a few free leaders left.  Most of the world’s petroleum supply is controlled by governments, a fact lost on the media and press, which in turn misleads billions of people.  Oil prices, marginal barrels, and energy invested vs. energy returned are all symptoms of a partially controlled and partially market driven system that has become a way to barely keep enough product available.

So whom will the consumer trust?  Is it a Saudi sheik, a Russian oligarch, a U.S. bureaucrat or a company working in a free economy answering to millions of stockholders, employees and customers?  All these know that press and media types will watch and report something or other, nearly certain to be badly biased, but the news in some fashion will get out. That might be enough to keep the clutching and grasping government ideas at bay for a bit longer.  Oddly, and contrary to sentiment, your interest is the same as the free independent oil company.  That doesn’t mean your future is bound to them though.

For now and the immediate future the smartest folks are watching what is known as “Big Oil”.  Your humble writer knows he needs them and obviously tends to root for those who provide and support the developed world’s lifestyle.  Rah. That said:

ExxonMobil is the largest Big Oil firm.  It also enjoys a reputation of being engineering oriented.  Other firms, such as Chevron have a more personal sense and community base.  These are forms of corporate culture, if you will.  By any measure the competitiveness is very much there – all the Big Oil companies mean to get you to be their customer.

So when a firm like ExxonMobil offers a blog by a vice president it’s worth some notice and the occasional stopping by.  All the while knowing these guys mean to sell petroleum products and keep doing that until another business model overtakes the industry.  They will not fail to use all lawful means to do just that – they owe it to the stockholders, employees and customers after all.

The blog is nearly two years old now, and is honestly, light on content. But there are some gems. It’s also a good start, now if we get them to post some information on the news and press releases from the R&D departments . . . Maybe even some useful information on where such an important part of the economy is looking into the future. Now that would be a blog!

Still, vice president Mr. Ken Cohen is going to be fully careful, run what’s written by the lawyers, and not break any rules.  But here’s a bit of business sense from out in the wild, never ask a lawyer’s approval, to pass on something or give over the gate keys.  Make ‘em earn their pay like everybody else – “approval not required, see that it gets done legally”.

So how after two years did ExxonMobil get a bit of attention?  A headline that sets up an energy density comparison between various energy sources, “How many gallons of gasoline would it take to charge an iPhone?”  Answer, a gallon would charge an iPhone daily for nearly twenty years.  Not bad, but the gem comes a bit farther in with, “A typical car’s gasoline tank contains less than 100 pounds of gasoline but can power a 3,000 pound car for 400 miles at 60 miles per hour.”  An astute observation.

When you look at the gem statement in the context, another attempt to maim ethanol as a fuel, the lawyers were likely consulted, but there is little sign any competent engineers were.  Is it any wonder people are so suspicious of Big Oil?

For now, though the illustration approximates reality, albeit years old, and its so stated if you read closely.  But one day an ethanol fuel cell may use 100 pounds of ethanol and power a lighter vehicle five times further at equivalent speeds.

Come on ExxonMobil and Mr. Cohen.  The firm projects and invests on ten-year plans or longer, there is a corporate culture of engineering and scientific status that leads the world. It was a good blog post until the swing at ethanol popped up.  We expect much more and far better of you and soon.

Coal to Liquid Artistic Graphic. Image Credit: SRI International.

Simply put, SRI has a method to make use of the dense proportion of carbon in coal and reform it with high content of hydrogen in natural gas to make liquid hydrocarbon products.  For the U.S. that has major energy security implications.

SRI’s promising new way to produce liquid transportation fuels from coal does not consume water or generating carbon dioxide.  The hydrogen that water provides in other processes is substituted by the natural gas.  With the energy requirement for hydrogen splitting from the water absent and the combustion of the coal the process reduces the CO2 produced.

The natural gas for water substitution also reduces the need to add energy to drive the gasification reaction, and results in the use of a smaller gasifier. In conventional coal to liquids approaches, energy is supplied by burning a portion of the coal feed, which then produces carbon dioxide. SRI’s approach makes it economical to use carbon neutral electricity, such as nuclear, hydro, or solar as a source of additional energy.

SRI Coal to Liquid Fuel Process Flow Diagram. Click image for the largest view. Image Credt: SRI International.

The new SRI process uses the hydrogen in the natural gas to convert coal making an uprated hydrogen rich syngas (a mixture of carbon monoxide and hydrogen). The coal first decomposes into volatiles and char while CH4 is converted into CO/H2 mixtures; the char is converted into CO/H2 mixtures via steam gasification on longer time scales.  The syngas is first converted into methanol that can then be efficiently processed to make the desired transportation fuels.

Based on data from their bench-scale tests, SRI engineers estimate that the capital cost for a full-scale plant using the new process would be less than half that of a conventional coal-to-liquids (CTL) plant that uses the familiar and common process called Fischer-Tropsch Synthesis (FTS). FTS produces only a small fraction of the hydrocarbons needed for fuel and requires extensive recycling.

SRI CTL Compared to FTS. Click image for the largest view. Image Credit:SRI International.

SRI has performed a series of analyses to examine the environmental impact of the technology under several scenarios. Conventional diesel comes in at 389 gCO2/mile, conventional FTS coal-to-liquids diesel at 830 gCO2/mile; and the SRI synthetic fuel at 326 gCO2/mile when using carbon-neutral electricity power. Based on their analyses, if diesel were produced using biogas as the natural gas source for the methane, the resulting emissions would be 190 gCO2/mile and the product would qualify as an alternative fuel under the revised Renewable Fuels Standard of the Energy Independence and Security Act of 2007. The Act requires alternative fuels to meet a standard of 50-percent reduction of greenhouse gas emissions compared to other fuels.  That will get the attention of the coal folks.

Ripudaman Malhotra, associate director of SRI’s Chemical Science and Technology Laboratory presented the process at the 28th Annual International Pittsburgh Coal Conference pointing out the SRI process converts all the carbon to product, reduces capital cost, has adjustable syngas ratios to produce CO + 2H2, ideal for methanol; and uses efficient COTS (commercial off-the-shelf) technology for the methanol to JP-8 conversion.

SRI estimates the efficiency of its CTL plant at 67% – significantly higher than traditional CTL plants, mostly because it is converting 100% of the carbon feed into product and it utilizes electricity generated off-site. Accounting for the heat rate of generating that electricity from a traditional coal plant would still result in a plant efficiency of 47%.

But those efficiencies are a bit misleading – The cost per gallon for the SRI diesel fuel product is calculated at $2.81.  That’s still higher than FTS at $2.14, where virtually all the energy comes from raw coal and a great share of the carbon is lost to CO2 in making the fuel and lots of energy goes to getting the hydrogen from water.

If the goal is low investment, downsized installations with low emissions and full use of the raw materials the SRI process is quite attractive.  That plus the process itself offers more than the middle distillates of diesel and jet fuel.  There’s crude methanol, gasoline, propylene, and propane as well – plus some mineral ash.

The SRI process likely has commercial legs.  Whether or not a facility is built will consider the raw materials cost along with the investment.  Another question comes to mind when looking over the process flow diagram.  Would any of the concepts here transition to the oil shale deposits of the western U.S.?

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

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

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

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

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

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

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

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

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

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

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

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

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

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

University of Alberta researchers have developed ROC as a way to replicate oil trapping rock layers and show energy producers the best way to recover every last bit of oil from these reservoirs.

Mechanical engineering professor Sushanta Mitra leads a team of University of Alberta researchers using an actual core sample from oil drilling sites to make 3D mathematical models of the porous rock formations that can trap huge quantities of valuable oil.

Recovering the oil trapped in porous layers of sandstone and limestone is a tricky and costly operation for energy exploration companies the world over.  But they all have core samples of their reservoirs.

Mitra explains, “The process starts with a tiny chip of rock from a core sample pulled from porous rock where oil has become trapped. That slice of rock is scanned by a Focused Ion Beam-Scanning Electron Microscopy machine, which produces a 3D copy of the porous rock. The replica is made of a thin layer of silicon and quartz at Nanofab, the U of A’s micro/nanofabrication facility.”

Reservoir on a Chip Sample. Click image for the largest view.

The team calls the finished little 3D model a Reservoir on a Chip.

Mitra continues, “The hugely expensive process of recovering oil in the field is re-created right in our laboratory.  The researchers soak the ROC in oil and then water under pressure is forced into the chip to see how much oil can be pushed through the microscopic channels, and recovered.

“ROC replicas can be made from core samples from oil trapping rock anywhere in the world,” said Mitra. “Oil exploration companies will be able to use ROC technology to determine what concentration of water and chemicals they’ll need to pump into layers of sandstone or limestone to maximize oil recovery.”

The research findings have been published as the back cover article in the journal Lab Chip, a publication of the Royal Society of Chemistry.

The new chip represents the individual pore structure of a naturally occurring oil-bearing reservoir rock. The pore-network has been etched in a silicon substrate and bonded with a glass-covering layer to make a complete microfluidic chip.  That makes it possible to perform traditional waterflooding experiments in a ROC. Oil is kept as the resident phase in the ROC, and waterflooding is performed to displace the oil phase from the network. The flow visualization provides specific information about the presence of the trapped oil phase and the movement of the oil/water interface/meniscus in the network.

The Alberta team is a little further along than a first glance suggests.  The paper contains the first indication that this oil-recovery trend realized at chip-level can be correlated to the flooding experiments related to actual reservoir cores.

Mitra and his team have successfully demonstrated that the conceptualized ‘Reservoir-on-a-Chip’ has the features of a realistic pore-network and in principle is able to perform the necessary flooding experiments that are routinely done in reservoir engineering.

This is no small thing – most of the oil, more than half, perhaps 75% or more is still in the ground.  The huge oil consumption to date could be only about a third of the inventory already at hand.  The University of Alberta team’s new reservoir modeling based on the actual rock below plus the new ways to describe the shape and circumstances of the oil and how the rocks are laid out may well discover even more reversions than current understood.

This is a great idea already on its way to being a proven working concept.  Great work folks.

Statoil’s major oil find, described as a “giant” by an investment partner last month is giving new life to fading North Sea output was significant.  Statoil plans to give a more precise estimate of the size within a couple of weeks.

Aldous Avaldsnes Lease Map. Click image for the largest view.

The little companies aren’t holding back on suggesting the new size.  Sweden’s Lundin Petroleum is saying that Avaldsnes/Aldous Major South, which could already be the biggest oil find made so far this year, may hold 1.2 billion to 2.6 billion barrels of oil equivalent.  At the peak estimate of 2.6 billion barrels it more than doubles the reserve.

2.6 billion barrels would be the third-largest find ever made on the Norwegian shelf. The original Statfjord and Ekofisk fields, which kicked off Norway’s oil era in the 1970s, each held more than 3 billion barrels.

Information is leaking out prompting outside analysts to up their estimates early too.  Statoil said through a spokesman to the media that an appraisal well drilled at the site proved an oil column of 50-55 meters (164-180 feet) quoted saying, “Discoveries are always positive, and this is a significant oil column.”

The new exploratory well is in the Avaldsnes/Aldous Major South field. The improvement comes from the Avaldsnes horizon.

North Sea comparisons need to include the British side to the west.  Buzzard, Britain’s largest oilfield, which feeds into the benchmark UK Forties crude oil production stream, was found 10 years ago with reserves of around 500 million barrels oil equivalent.  BP’s current news has just announced it will be developing off the west of Shetland the 640 million-barrel Clair Ridge oil field.

Its worthwhile to note that over the last 10 years, new oilfield discoveries in the British sector of the North Sea have contained only averages of around 20 million barrels each.  Both sides of the North Sea are increasing reserves at much larger rates.

The Norwegian government agency, the Petroleum Directorate, which manages Norway’s oil and gas resources, is being cautious, suggesting production could begin in 2018-2019.  Lundin is working toward 2017 and Statoil 2018.

For now the Norwegian Petroleum Directorate and Statoil, aren’t confirming Lundin’s numbers as they complete more analysis on the size of the find, although both acknowledge the find is undoubtedly large.

Norway’s North Sea oil production peaked in 2001 and has fallen since. In 2010 the Nordic country produced 1.8 million barrels per day.  It looks like the production rate will soon stabilize and climb back up.

The Avaldsnes/Aldous Major South field could be 3rd biggest ever-made in Norway’s side of the North Sea.  We’ll be looking for the oil type and quality news and get a sense of how this oil will affect the world oil refining system and pricing.  Summing up old discovery initial, secondary, tertiary production and these new finds are going to make the North Sea an even more important supply source for Europe.

The North Sea Hunt isn’t over yet.

The past 25 years has seen world oil sales increase 50% since 1986.  Freeing the communist block has consequences like consumers who can afford an energy-supported lifestyle.  The forecast for this year is oil will be used at a daily rate of 89 million barrels a day.  The increases aren’t likely to drop worldwide anytime soon.

If you believe in bureaucrats, the U.S. Energy Information Administration (EIA) has world oil consumption forecast up to between 108 million to 115 million barrels per day in the next 25 years. The forecast range accounts for a low-side oil price of $50, and a high-side price of $200. At the low range the consumption is expected to grow by 21% from today’s levels.

With the big, easy and low cost oil deposits pretty much found for now many (peak oil, oil doomers and others) wonder where all that oil is going to come from.

Oil production is a multiyear investment from discovery to gas in the tank.  The US consumers chew through more than 22% of world production – a third more than the European Union, and about twice China’s rate.  Both of these major markets have larger populations than the U.S.

Before OPEC and embargos, a freed Russia and the other major oil production matters the U.S. back in 1970 only imported 1.3 million barrels a day and produced 9.6 million.  It took until 1994 for oil imports to surpass the U.S. production.  By 2005 imports were double the U.S. production.

The ensuing 6 years have shaved off some consumption and increased U.S. production.  Imports are off now 1.3 million barrels per day from the 2005 peak.  Consumption in the U.S. is sensitive to the economy and prices.

But the big news is in U.S. production.  The 2008 low of 4.95 million barrels per day was the lowest back to 1946.  One might point out in 1946 the U.S. was producing about half of the world’s oil, a stark contrast from 2008 volume in which it only produced 6% of the total global supply.

Faced with smaller, harder to find, more expensive to produce oil fields, foreign oil was cheaper to buy. The US’s production decline was deemed and declared as irreversible by pundits and politicians, while consumers had to allocate ever larges shares of budgets for an oil dependence needing an ever-larger fill up from foreign sources.

U.S. production growth in 2009 killed the assertion of an irreversible downward production trend. And 2009’s 8.3% increase in production to 5.4m bpd not only broke a streak of 17 consecutive years of declines; it marked a new trend that is showing the reversal to be the real thing.  Based on annualized production figures from the first half of 2011, the U.S. is on pace for its third consecutive year of production growth. Over this time domestic production will have grown by 12%, adding nearly 600,000 barrels per day.

It’s expected that this trend will continue for many years to come. The EIA sees U.S. production exceeding 6 million barrels per day by 2018, with the possibility of exceeding 7 million per day by about 2025.  Many experts believe these volume estimates to be conservative.

With those very low prices in the 1980s and 1990s keeping search and development near a standstill, the past few years have reignited the search and development side of the oil business.  But most importantly more revenue has opened technology’s door.

Advances in horizontal-drilling and hydraulic-fracturing methods have opened up vast resources within large shale-oil formations that underlie the US.

Horizontal drilling is not new. In fact, it has been a work-in-progress in the oil industry for over 50 years. What’s really revolutionized this method of recent is vast improvements in drilling equipment and radical innovations in down-hole monitoring instrumentation. Drillers can now guide their bits at the precise angles and degrees to access longer portions of deep thin and tight reservoirs.

Precision horizontal drilling is essential when trying to recover oil from massive shale formations like the prolific Bakken field that underlies the Williston Basin in North Dakota and Montana. The Bakken’s thin band of continuous crude filled rock stretches across 25,000 square miles, with the main pay zone about two miles below the surface. However the zone only has a maximum thickness of about 150 feet, while many spots are squeezed to less than 50 feet.  Historically, operators had little success drilling vertical wells straight down through the pay zone.

With horizontal drilling the reservoir is essentially flipped on its side, thus greatly extending the hole through the pay zone. Instead of pumping oil from just a small vertical hole of a large thin horizontal reservoir, the Bakken’s operators drop their wellbores into this rich formation and extend them laterally off to the side. Many of these wells have holes drilled two miles in length laterally through the pay zone.

Shale is a tight oil-bearing rock requiring another major step to harvest an economic flow of oil production. Getting oil out of a tight shale rock is an active process, the oil must be provided with pathways to flow to the well.  To do so an operator must stimulate the host rock using hydraulic fracturing (fracking).

Fracking is not new either; it too has been around for over 50 years and has been a work-in-progress in the oil industry.  In recent years have new innovations in fracking allowed formations like the Bakken and the new and exciting deeper Three Forks formation to see wildly positive economics. Advances in multistage fracking have allowed operators to maximize drainage across the entire lateral, revolutionizing the way petroleum engineers are approaching shale-oil development.

Oil operators are still in the early stages of uncovering the Williston Basin’s enormous potential and are making amazing progress as seen in the Bakken’s robust production growth. Production has grown from about nothing in the early 2000s to over 400,000 barrels per day in 2011.  Many project Bakken production to exceed 1 million barrels per day soon. The two technologies form a significant and material output that is one of the major reasons for the US’s new upward trend.

Its technology applied with oil prices high enough to make them affordable.  Maybe the price of oil products like gasoline doesn’t seem so affordable, but the alternative is to bid for more imported oil, or cut use dramatically.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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