Oil, again

[TorpedoBreath]

Because of Securities Exchange Commission guidelines for booking reserves there are lots of potentially recoverable hydrocarbon volumes acknowledged internal to all oil and gas companies. They just aren't allowed to tell you about their volumes unless they are "reasonably certain" they will produce them. Most interpret that to mean P90. So if you, like many humans think of likelihood of an event happening in P50 terms, then you'd come up will a much larger oil reserves number than the SEC will allow to be published in financial disclosure documents.

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I personally think it has to do with the oil companies keeping the supply artifically low so they can sell for more money and have the supply last longer.

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That's not a very Republican thing to say, and it's likely false.

I tend to agree with sam h's explanation.

[Cyrus]

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Crude oil reserves. The problem with this number, be it 40 years or 80 years is that it's pointless. You can't produce at full speed until the well is dry.

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When the well is getting near dry, you are producing at somewhat reduced capacity, that is true. But this effect is not the important point. What's important is to get a meaningful figure out to guide us. When the reserves-to-production ratio rises, that means something, as it does when it drops. And knowing that we have ahead of us "40 years" also means something.

At least, it should.

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It's ... somewhat intellectually dishonest to report numbers quoting "today's production" when demand is growing.

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That's a standard compromise in finance. It's the same way you assess a company's performance at year's end : You take a snapshot which freezes the company's position at the 31st of that year and shows you receivables, payables, 12-month earnings, etc, at that point in time.

It's not perfect but it does the job.

Therefore, what one should do is take into account both the photograph (:current state of production) and the coming attractions (:forecasts of production growth).

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As for the argument on why not more refineries are built, there are other explanations possible, more or less likely.

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I would really like to know about them. (I trust you are not talking about regional problems, such as environmentalists stopping the construction of a refinery.)

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The thing I don't get is that if we will have demand growing even more the coming years, as seems to be the forecasts, then why [would Big Oil] believe prices will come down?

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I would tell you but then I'd have to kill you.

[Il_Mostro]

Yes they are.
It's not a secret that you can't produce at any rate you want to, you will damage the fields if you try. It has happened at a few places. And some (Simmons and others) argue that SA is basically at that point now, that the really can't increase production very much without seriously harming them.

[PorscheNGuns]

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Oil companies do not expect the current high levels of prices and margins to last more than one or two years down the road.

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Steve Forbes agrees with you. http://heraldsun.news.com.au/common/story_page/0,5478,16441087^664,00.html

-Matt

[sam h]

Thanks Mostro.

Follow up question: If there may be a "hard" ceiling on annual worldwide oil supply, one that will clearly not be sufficient to meet demand without a major change in consumption patterns, then why do arguments for or against the idea of a pending oil crisis tend to focus upon the size of reserves? It seems like that is relevant, but kind of beside the point. As long as annual supply capacity has a ceiling that demand will outpace, the crisis (at least in terms of continued high prices or rising prices) is coming no matter how much is down there.

[Il_Mostro]

Allow me to speculate a bit..
Firstly, the ceiling is not known, and I would belive it is dependant on how large the reserve is, the larger the reserve, the faster you can pump it out without damaging the field. And reserves are not known, some argue 2 GB ultimately recoverable, some 8.
So much of the argument is that we cannot know( and therefore we should assume we are not near the ceiling).

The fact that the crisis is coming, in terms of higher prices, isn't really anything to doubt. But the timing of it is very much in dispute. But my belif is that whenever it comes, be it now or in 20 years, we will still be fundamentally unable to cope with it, since as long as oil keeps flowing it will be the cheapest liquid fuel source there is, thereby inhibiting any real effort to change. And when we really starts to see demand oustripping supply (I know, this is something an economist will cringe when reading) we will see higher prices, and relatively fast rising.

[Il_Mostro]

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When the well is getting near dry, you are producing at somewhat reduced capacity, that is true.

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I'd argue it's a bit more than "somewhat". There are really two different problems here
1) Via advance recovery you manage to produce at almost full speed until the field more or less collapses, we have seen this at many fields lately, dropping 10%-20% in production in a single year. This is bad news since it's very quick and leaves little time to act.
2) The field is produced more carefully and will therefor have a long period of relatively slow decline. This is better, but not happening a lot, since a lot of these advance methods are used.
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But this effect is not the important point. What's important is to get a meaningful figure out to guide us.

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I agree that there is a point in that too. The problem is that the second part of the guide is often droppen, it's not "we have 40 years of production in theory, in reality we will have longer but will face supply problems. It's "We have 40 years". But you are of course right in that even this should say us a lot more than it does. If we say, we have 40 years, and also say, it will take 20-30 years to find an alternative, best case. Well, that really should tell us something...

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It's ... somewhat intellectually dishonest to report numbers quoting "today's production" when demand is growing.



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That's a standard compromise in finance. It's the same way you assess a company's performance at year's end : You take a snapshot which freezes the company's position at the 31st of that year and shows you receivables, payables, 12-month earnings, etc, at that point in time.

It's not perfect but it does the job.


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In some cases it does, in some it don't. I've seen argument for using liquefying coal that states that we have 200 years worth of coal (at present consumtion). But when looking more into it it turns out that if we increase the usage as much as the coal2oil would mean we only have 50 years, or 40. Just pointing out that one must be aware of the assumptions made.

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As for the argument on why not more refineries are built, there are other explanations possible, more or less likely.



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I would really like to know about them. (I trust you are not talking about regional problems, such as environmentalists stopping the construction of a refinery.)


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I'm not, although that might be an issue as well.
But if oil-companys are having a harder time finding oil, a harder time getting good business opportunites to pump more oil than they are now, well, why build? After all, supply won't increase a lot.

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I would tell you but then I'd have to kill you.

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watch it, I've got a black-belt in video-violence.

[natedogg]

I don't have the expertise to evaluate these two articles, but I found them interesting. The first from :
http://www.geotimes.org/june03/NN_gulf.html

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Raining hydrocarbons in the Gulf

Below the Gulf of Mexico, hydrocarbons flow upward through an intricate network of conduits and reservoirs. They start in thin layers of source rock and, from there, buoyantly rise to the surface. On their way up, the hydrocarbons collect in little rivulets, and create temporary pockets like rain filling a pond. Eventually most escape to the ocean. And, this is all happening now, not millions and millions of years ago, says Larry Cathles, a chemical geologist at Cornell University.

"We're dealing with this giant flow-through system where the hydrocarbons are generating now, moving through the overlying strata now, building the reservoirs now and spilling out into the ocean now," Cathles says.

He's bringing this new view of an active hydrocarbon cycle to industry, hoping it will lead to larger oil and gas discoveries. By matching the chemical signatures of the oil and gas with geologic models for the structures below the seafloor, petroleum geologists could tap into reserves larger than the North Sea, says Cathles, who presented his findings at the meeting of the American Chemical Society in New Orleans on March 27.

This canvas image of the study area shows the top of salt surface (salt domes are spikes) in the Gas Research Institute study area and four areas of detailed study (stratigraphic layers). The oil fields seen here are Tiger Shoals, South Marsh Island 9 (SMI 9), the South Eugene Island Block 330 area (SEI 330), and Green Canyon 184 area (Jolliet reservoirs). In this area, 125 kilometers by 200 kilometers, Larry Cathles of Cornell University and his team estimate hydrocarbon reserves larger than those of the North Sea. Image by Larry Cathles.

Cathles and his team estimate that in a study area of about 9,600 square miles off the coast of Louisiana, source rocks a dozen kilometers down have generated as much as 184 billion tons of oil and gas — about 1,000 billion barrels of oil and gas equivalent. "That's 30 percent more than we humans have consumed over the entire petroleum era," Cathles says. "And that's just this one little postage stamp area; if this is going on worldwide, then there's a lot of hydrocarbons venting out."

According to a 2000 assessment from the Minerals Management Service (MMS), the mean undiscovered, conventionally recoverable resources in the Gulf of Mexico offshore continental shelf are 71 billion barrels of oil equivalent. But, says Richie Baud of MMS, not all those resources are economically recoverable and they cannot be directly compared to Cathles' numbers, because "our assessment only includes those hydrocarbon resources that are conventionally recoverable whereas their study includes unconventionally recoverable resources." Future MMS assessments, Baud says, may include unconventionally recoverable resources, such as gas hydrates.

Of that huge resource of naturally generated hydrocarbons, Cathles says, more than 70 percent have made their way upward through the vast network of streams and ponds, venting into the ocean, at a rate of about 0.1 ton per year. The escaped hydrocarbons then become food for bacteria, helping to fuel the oceanic food web. Another 10 percent of the Gulf's total hydrocarbons are hidden in the subsurface, representing about 60 billion barrels of oil and 374 trillion cubic feet of gas that could be extracted. The remaining hydrocarbons, about 20 percent, stay trapped in the source strata.

Driving the venting process is the replacement of deep, carbonate-sourced Jurassic hydrocarbons by shale-sourced, Eocene hydrocarbons. Determining the ratio between the younger and older hydrocarbons, based on their chemical signatures, is key to understanding the migration paths of the oil and gas and the potential volume waiting to be tapped. "If the Eocene source matures and its chemical signature is going to be seen near the surface, it's got to displace all that earlier generated hydrocarbon — that's the secret of getting a handle on this number," Cathles says.

Another important key to understanding hydrocarbon migration is "gas washing," Cathles adds. A relatively new process his research team discovered in the Gulf work, gas washing refers to the regular interaction of oil with large amounts of natural gas. In the northern area of Cathles' study area, he estimates that gas carries off 90 percent of the oil.

Ed Colling, senior staff geologist at ChevronTexaco, says that identifying the depth at which gas washing occurs could be extremely useful in locating deeper oil reserves. "If you make a discovery, by back tracking the chemistry and seeing where the gas washing occurred, you have the opportunity to find deeper oil," he says.

Using such information in combination with the active hydrocarbon flow model Cathles' team produced and already existing 3-D seismic analyses could substantially improve accuracy in drilling for oil and gas, Colling says. ChevronTexaco, which funds Cathles' work through the Global Basins Research Network, has been working to integrate the technologies. (Additional funding comes from the Gas Research Institute.)

"All the players are looking for bigger reserves than what's on shore," Colling says. And deep water changes the business plan. With each well a multibillion dollar investment, the discovery must amount to at least several hundred million barrels of oil and gas for the drilling to be economic. Chemical signatures and detailed basin models are just more tools to help them decide where to drill, he says.

"A big part of the future of exploration is being able to effectively use chemical information," Cathles says. Working in an area with more oil by at least a factor of two than the North Sea, he says he hopes that his models will help companies better allocate their resources. But equally important, Cathles says, is that his work is shifting the way people think about natural hydrocarbon vent systems — from the past to the present.

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and the next, from a recent futurepundit post:

http://www.futurepundit.com/archives/002981.html#002981

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Shell Oil Shale Extraction Technology Economically Viable?

The development of an economically viable way to extract oil from oil shale would put a ceiling on oil prices and would extend the oil era by decades. It would also increase the odds of significant global warming. Well, in light of all that a variety of media outlets are reporting that Shell Oil thinks it can produce oil from oil shale at $30 per barrel using an in situ process where the shale is cooked without first mining it onto the surface.

They don't need subsidies; the process should be commercially feasible with world oil prices at $30 a barrel. The energy balance is favorable; under a conservative life-cycle analysis, it should yield 3.5 units of energy for every 1 unit used in production. The process recovers about 10 times as much oil as mining the rock and crushing and cooking it at the surface, and it's a more desirable grade. Reclamation is easier because the only thing that comes to the surface is the oil you want.

And we've hardly gotten to the really ingenious part yet. While the rock is cooking, at about 650 or 750 degrees Fahrenheit, how do you keep the hydrocarbons from contaminating ground water? Why, you build an ice wall around the whole thing. As O'Connor said, it's counterintuitive.

Shell is just now moving onto the next stage to decide by 2010 whether their process is commercially feasible.

Shell has received approval from Rio Blanco County, state and federal officials to conduct a $50 million, two- to four-year study of a groundwater freezing process, said Jill Davis.

“We’re still looking to decide if we’ll move on to commercial production by the end of the decade,” she said. “It’s been promising, so we want to take it to the next level with an environmental test of our ‘freeze wall’ process.”

Refrigerants, such as ammonia dioxide, are circulated through underground pipes to freeze the groundwater and earth to keep groundwater out of an oil-shale formation.

“We’ve tested the process in a circular pattern and this will be a football field-shaped rectangle in an area more like where commercial production could happen,” she said.

Some estimates for the amount of oil in shale range as high as 1 trillion to 1.8 trillion barrels. Assume that 1 trillion barrels could be extracted. The United States currently uses about 20.5 million barrels per day which is about a quarter of current world oil demand. World oil demand is projected to rise to 119 million barrels per day by 2025 or about a 50% increase. Suppose we take that 119 million barrel figure and round it off to 120 million barrels. Also let us assume that oil shale could yield 1 trillion barrels of oil. That oil shale would satisfy total world oil demand by this equation: 1,000,000 million barrels/(365 days per year times 120 million barrels per day) which equals only 22 years at the projected year 2025 consumption rate. Even oil shale can delay the end of the oil era by a couple of decades. Still, we could use those decades to develop technologies to lower the cost of nuclear and photovoltaic solar power.

A recent RAND corporation report with lead author James Bartis argues the US government should add oil shale to its energy research portfolio.

Since the future prospects for oil shale remain uncertain, the RAND report recommends that the federal government refrain from major investments in oil shale development until the private sector is prepared to commit its technical, management and financial resources. However, the report recommends a few low-cost efforts that can begin in the near future to move oil shale development forward.

The report by the RAND Environment, Energy and Economic Development program says that between 500 billion and 1.1 trillion barrels of oil are technically recoverable from high-grade oil shale deposits located in the Green River geological formation, covering parts of Colorado, Utah and Wyoming.

The mid-point of the RAND estimate – 800 billion barrels – is three times the size of Saudi Arabia's oil reserves. This is enough oil to meet 25 percent of America's current oil demand for the next 400 years.

The benefits of a competitive oil shale industry are substantial. For an output of 3 million barrels per day, the study estimates direct economic benefits of about $20 billion per year. Federal, state and local governments would receive about half of this amount in the form of lease payments, royalties and taxes.

Production at 3 million barrels per day also could likely cause oil prices to fall by 3 to 5 percent, saving American oil consumers roughly $15 billion to $20 billion annually, according to the report. A multimillion-barrel per day oil shale industry could also create several hundred thousand jobs in the United States.

The in situ process may avoid many of the environmental problems that arise from oil shale mining.

Another technical development that has been taking place involves heating the oil shale while it is still in the ground – a process called in-situ conversion. Mining is not required. Instead, electric heating elements are placed in bore holes, slowly heating the shale oil deposit. The released liquids are gathered in wells specifically designed for that purpose.

In contrast to surface mining, in-situ conversion does not permanently modify land surface topography and may be significantly less damaging to the environment. Small field tests conducted by Shell Oil involving an in-situ approach appear promising. While larger scale tests are needed, Shell anticipates that this method may be competitive with crude oil priced below $30 per barrel. RAND has not developed an independent estimate of the price level needed to make in-situ conversion competitive.

On the environmental side, adverse land and ecological impacts will accompany oil shale development no matter which approach is used. Oil shale production will also result in airborne and greenhouse gas emissions that could severely limit oil production levels.

Colorado has the largest oil shale deposits and some deposits have more oil per ton of rock.

Steve Wiig, geologist for the Rock Springs BLM office, said Wyoming oil shale, on average, would produce 15 to 30 gallons of oil per ton of oil shale rock. He said the Colorado and Utah deposits could produce 30 to 40 gallons, with some sites capable of producing 60 gallons of oil per ton of oil shale.

Another company says it can produce oil from shale even more cheaply using a more conventional approach.

For example, one of the star witnesses of Gibbons' hearings was Jack Savage, president of Utah-based Oil-Tech Inc. He said the company is ready to start cooking oil out of shale with a retort it has built near Vernal, Utah.

"We have been working on this for 15 years," Savage said. "Now we're ready to go."

Savage, once president of companies that manufactured golf bags and other sporting goods, said he can turn shale into oil for $10 to $22 a barrel, depending on market conditions. Savage pushed for an accelerated federal leasing program, but he's already leased 38,000 acres of state land in Utah and says he's working on a research-and-development bid to continue work on his project.

The biggest problem with mining oil shale comes as a result of heating oil shale rock. The rock expands in size and then can't just get put back where it was excavated.


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[Cyrus]

If the thesis of the article was that there is just not enough crude oil to go around, I disagree. Crude oil production is not the issue -- refining is. As the stats show, refineries are operating at close to full utilisation in 2004 and 2005. (Which, come to think of it, is amazing when you factor in the numerous shut-downd around the world, when refineries were closing down temporarily to upgrade their products' specifications.)

There has been a huge surge in demand, with Asia-Pacific (read: China) leading the way.

OPEC could double the daily production of crude oil tomorrow (a strictly theoretical argument) and the price of oil products would be affected only slightly.

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If annual [crude] oil production has a ceiling, then you don't want to build refineries that would bring annual oil refining capacity past that ceiling.

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The world is currently pumping out all the crude that the refineries need. But the refineries do not produce enough of what the world needs.