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

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

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

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

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

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

Ford Super Duty Available with Compressed Natural Gas Fueling

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

This is good and very welcome news.

The area off east Africa has yielded a series of huge discoveries over the past couple of years.  Simon Ashby-Rudd, an oil investment banker at Standard Bank in the UK puts it this way, “With gas exploration you have to find an elephant field to make it worthwhile. They (oil exploration firms) didn’t just find one elephant – they found a herd of them.”

Mozambique and Tanzania, which until recently did not even feature on the world energy map, have become some of the gas industry’s hottest real estate.

East Africa Political Map

The earlier players are Cove Energy, a small Africa-focused oil and gas explorer with an 8.5 per cent stake in a big gas field in Mozambique, Anadarko Petroleum and Eni of Italy. Their two fields combined could contain up to 60 trillion cubic feet (tcf) of recoverable resources of gas – nearly as much as Kuwait’s entire reserves.

The speculation is that should be enough to turn Mozambique into a key exporter of liquefied natural gas, or LNG, to China and India.

The region is still barely explored. Much more gas should turn up.  The exploration group Afren says less than 500 wells have been drilled in all of east Africa, compared with some 20,000 in the north and nearly 15,000 in the west of the continent.  Those areas are still turning out new reserves.

Claudio Descalzi, chief operating officer of Eni’s exploration and production division said its field discovery was “one of the most important we’ve had in our history, in terms of the quality of the reservoir, its dimensions and the markets it’s close to. It’s transformational for us.”

All this could be an economic transformation for Mozambique and Tanzania.  The U.S. firm Anadarko is proposing a massive liquid natural gas plant in Mozambique estimated to cost about $25-billion (U.S.) – more than twice the country’s gross domestic product. The World Bank ranks Mozambique 204 out of 215 nations in terms of per capita income.  That brings the question up about governance and if the wealth will affect everyone there fairly. It could turn one of the world’s poorest nations into one of the richest.

However, and this is a big one just to start – this is pirate territory. The Somali pirates already harass Statoil who has naval patrols guarding its drilling operations.   African waters can be treacherous, Statoil has lockdown facilities on all its rigs and support vessels to keep staff safe in the event of a pirate attack, while a small flotilla of boats, operated by security contractors and Tanzanian navy personnel, guard the drilling site.

Now Eni, Anadarko and little Cove are firmly anchored in Mozambique.  Statoil has a big find.  Shell, Petrobras and Exxon Mobil are now setting up shop in Tanzania.  Usually in these situations the leading little firms sell out for big payoffs to the majors who have the expertise, engineering staff and capital to get giant discoveries to market.

Liquefaction of natural gas doesn’t come cheap.  It’s a multibillion dollar exercise for each facility and billions more to find and pipe in the gas as well as load it out for shipping.

Anadarko, one of the best dealmakers in the oil business has already announced it is looking to sell some of its stake in the Mozambique field.  Little Cove simply put itself up for sale in January.

The independent oil firms are not standing around, the pace of drilling is picking up. Morgan Stanley expects 23 wells to be drilled off Kenya, Tanzania and Mozambique this year, almost double the number in 2011.

Its enough to make the folks around the American Gulf of Mexico coast quite disappointed and piqued at the U.S. federal government for letting the business get away.

Still, this will be a blessing for crude oil prices over time.  There’s a lot more market penetration for compressed natural gas (CNG) in Asia than the U.S.  Every vehicle that’s built or converts to CNG fuel is one less using oil.

Now if the local folks can get the governance right and not start another messy war this could look very good for the world’s energy markets.

3M's Sampling of Pressure Vessels.

CNG has often been suggested to be a good replacement for gasoline.  It is; its simpler to get to proper emissions, burns clean, has workable octane, and it could be generally available without an entirely new infrastructure.  Natural gas is already piped to most every place but the rural areas of the U.S.  As a fuel substitute it would work pretty well.

On the other hand, while switching over isn’t totally simple, it isn’t something many would be advised to do in the home garage.  The equipment needed for metering and pressure regulation isn’t particularly expensive, but to get a tank with worthwhile capacity is an expensive barrier.

That’s where 3M and Chesapeake are jumping in – Chesapeake has the gas and 3M the technology.  Currently the fuel tank on a CNG vehicle is its most expensive single component.  The plan is the new CNG will reduce costs while increasing performance. Less expensive tanks will enable greater market adoption of CNG as an alternative automotive fuel source.

Chesapeake has pledged through Chesapeake NG Ventures Corporation (CNGV) an initial $10 million investment toward design and certification services, market development support and a commitment to use the new tanks for its corporate fleet conversion to CNG.  Chesapeake NG Ventures Corporation was established in 2011 to identify and invest in companies and technologies that will replace the use of gasoline and diesel derived primarily from foreign oil.

CNGV has committed expenditures of  $1 billion spread over the next 10 years to help fund various initiatives to increase demand for natural gas.  The big investments so far include $300 million in Clean Energy Fuels Corp. and privately held Sundrop Fuels, Inc.

On the technical side 3M has subcontracted with Hypercomp Engineering, Inc. of Utah for the design and certification of tanks. 3M will do the actual tank manufacturing and focus its capital on all future operations and production. 3M expects the tanks to be available for sale during the fourth quarter of 2012.

3M’s CNG tank solution is a combination of the company’s proprietary liner advancements, thermoplastic materials, barrier films and coatings, and damage-resistant films in an effort to transform the pressure vessel industry. Using nanoparticle-enhanced resin technology and 3M™ Matrix Resin for Pressure Vessels, 3M will create CNG tanks that are 10 to 20 percent lighter with 10 to 20 percent greater capacity, all at a lower cost than standard vessels.

Add to that the 3M technology is said to produce safer and more durable tanks than the common heavy welded steel models currently on the market. The tank innovation builds on 3M’s proven history of developing and introducing pioneering technologies to the market.

This may be a significant modality for transport fuel change.  George Buckley, Chairman, President and Chief Executive Officer of 3M said, “3M believes in the potential of natural gas, and this agreement illustrates our commitment to the industry. We are excited about this collaboration to speed the development and adoption of natural gas-powered vehicles.”  With a presales investment of $10 million that has to be a happy CEO.

So far there are only little areas of CNG market success.  But lots of places and some fleets have looked or started adopting conversions.  The incentives are strong – there’s more than a 100-year supply of natural gas in the U.S. and lots more is available to come on line.  Natural gas priced equivalent to a gasoline gallon comes in at only $1.00 to $2.00.

Basically it boils down to this: the fuel is plentiful, affordable and domestically produced.

Our thanks for this push on the opportunity goes to Aubrey K. McClendon, Chesapeake’s Chief Executive Officer who said, “This partnership brings together two leading companies from different sectors, both committed to advancing the natural gas transportation fuel market. We applaud 3M for recognizing the future of natural gas as a low-cost, cleaner alternative to gasoline, and for creating innovative tank technology that will make natural gas vehicles more affordable and accessible to fleets and individual consumers nationwide. Our country needs a solution to break the foreign stranglehold on our fuels market, and today’s announcement is another step to transition our nation away from costly imports.”

The numbers aren’t being touted yet for consumer comparisons.  It’s very likely that the cost per mile by CNG is going to be less.  If 3M gets its marketing act together there won’t be any gouging by shops to do conversions.  We may even have a brief holiday from fuel taxes until the Feds and States catch up.

The meaningful number is going to be access to fueling – for a while getting filled isn’t going to be convenient.  It’s not impossible now, but there will be to be quite a bit of organizing to get a to growing market that has ready access.

For many the biggest question is going to be how the old gas tank compares in range to the new CNG tank.  That’s a big if.  If 3M can cut the weight by 20% and increase the capacity by 20% one has to wonder how close that gets to the gasoline range.

The timing is good – the gasoline price forecast, albeit dubious, has gasoline headed past $4 a gallon.  That makes $1.50 very attractive indeed.

I think I’ll be signing up . . .

A midsize oil explorer and developer company called McMoRan has been working in shallow Gulf of Mexico waters, close to shore, but drilling very deep.  For years McMoRan has been ignored.  Until:

Chevron, the Big Oil Giant out of California caught on to the potential.  Chevron is so impressed there have been mentions of the little McMoRan company, a very rare thing in the Big Awl Bidness.  But Chevron is a California firm – sort of people oriented more than the others.

As a practical matter Chevron is practically beating the drum – by oil company standards. Chevron has begun promoting the Shallow Water Gulf of Mexico (SWGM) as one of its top three areas of geologic interests worldwide.  Keep in mind Chevron is a major firm from the U.S. to Australia, across Africa, central Asia and South America.  If SWGM is in the top three, the prospects must be huge.

This is significantly important – an earlier well called Blackbeard East turned out to have a formation measuring 300 feet thick and appears to be a hydrocarbon bearing fractured carbonate.  A huge percentage of the world’s most prolific oil and gas deposits have been found in fractured carbonate structures.  Fractured carbonates sometimes naturally give up their deposits very easily. This could be a major discovery.

Fractured Carbonate Surface Exposure in the Pyrenees Mountains

Chevron is also very well positioned.  Chevron started a well late last year onshore in Cameron Parish, LA called Lineham Creek with a proposed total depth of 29,000 feet targeting the Eocene and Paleocene objectives below the salt structure.  The oil lease is a bit historical on land known as the Rockefeller Preserve that was donated to the State of Louisiana years ago.  The Rockefellers kept the royalty rights on the land and passed them to Chevron.

McMoRan’s lead guy, Jim Bob Moffett, isn’t being ignored anymore – the company’s expertise in SWGM is quite important now.  Five years of success has value with the current demand for more production.  Chevron invited McMoRan to partner in its well.  This is a big deal – significant in that Chevron wanted MMR to join the project as an equal partner.  McMoRan has negotiated a 36% participation and Chevron is also partnering with McMoRan’s partners EXXI for 9%, and W.A. “Tex” Moncrief for 5%.

This information points to some important facts.  The new well is located halfway between (on an east/west axis) McMoRan’s Davy Jones well and Chevron’s Bear Hump well which has been completed and is now being evaluated.  The McMoRan well follows projects called Blackbeard West, Blackbeard East, Lafitte, and the Davy Jones.  That experience is now critical for anyone looking for petroleum in the general area and at the depths below 20,000 feet that have become the new exploration frontier.

This month Bobby Ryan, Chevron’s VP of Global Exploration, spoke at another oil and gas conference about their enthusiasm for the SWGM and the work they are doing with McMoRan.  Ryan pointed out the deep drilling is a new effort in an already matured basin.  Chevron already has major acreage from wells drilled long, long ago and that are still producing to retain the leases.  Chevron it seems, has a royalty share in the McMoRan Davy Jones well.

In an odd twist, Chevron has also obtained access to the Davy Jones well logs, geological evaluations and interpretations, which would not normally be available to a royalty interest holder. Yet Mr. Moffett has made it quite clear he intends to bring in a partner with very deep pockets to help develop these ultra deep wells. It all makes sense now and appears to be getting underway very quickly.  It looks like Chevron and McMoRan are in for a long-term close association deal.

For decades experts have assured that there was nothing to find deep in SWGM.  But now we’re finding the formations have natural gas and it looks clear the reservoirs extend onshore.  That old assurance looks awful far off the mark now.  Just what the production rates might turn out to be isn’t being released yet, but the executive excitement and deal making is based on hard info prepared by reserve engineers that are heavily scrutinized.

For consumers this is great news from an additional viewpoint.  The SWGM work is in an area where there are existing pipelines to carry the new reserves to market right away. Billions of dollars will not have to be spent over the coming years and interminable waits to get permitting are avoided.  This discovery and development isn’t vulnerable to a crass political presidential delay.

Congratulations!  Go McMoRan and Chevron!

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.