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Is "shale oil" the answer to "peak oil"?
Posted by Gail the Actuary on March 4, 2011 - 10:56am
Readers have been asking questions about a couple of shale oil articles recently. One is an AP article called New drilling method opens vast oil fields in US. A similar article is a CNBC article titled Massive New US Oil Supply – ‘Peak Oil’ Fears Overblown? Both of these articles talk about the extraction of shale oil in the Bakken and other locations, using horizontal wells and hydraulic fracturing.
According to the AP article:
Companies are investing billions of dollars to get at oil deposits scattered across North Dakota, Colorado, Texas and California. By 2015, oil executives and analysts say, the new fields could yield as much as 2 million barrels of oil a day — more than the entire Gulf of Mexico produces now.
This new drilling is expected to raise U.S. production by at least 20 percent over the next five years. And within 10 years, it could help reduce oil imports by more than half, advancing a goal that has long eluded policymakers.
There are several questions that might be asked:
1. Is this really a new drilling technique?
2. How likely is the 2 million barrels a day of new production, and the 20% increase in US production, by 2015?
3. Can this additional oil supply really reduce the US’s imports by over half?
4. How much of a difference will this oil make to “peak oil”?
Let’s take the questions in order.
1. Is this really a new drilling technique?
No., this is not really a new drilling technique. According to Wikipedia, hydraulic fracturing was first used in the United States for stimulating oil and gas wells in 1947. It was first used commercially in 1949. Directional drilling, including horizontal drilling is almost as old, but it was not widely used until down-hole motors and semicontinuous surveying became possible. The techniques have gradually been refined, as oil and gas companies have used them more and supporting technologies have been better developed.
A major reason we are using these techniques is because much of the easy-to-extract oil has already been extracted. Horizontal drilling and hydraulic fracturing are more expensive, but can be used to get out oil that would be inaccessible otherwise. The hope is that oil prices will be high enough to make these techniques profitable.
2. How likely is the 2 million barrels a day of new production, and the 20% increase in US production, by 2015?
That is a good question. There is certainly a lot of drilling for oil being done now. According to Baker Hughes, 805 rigs are now involved in oil drilling. This is above the oil rig high point in 1987. (Natural gas rig counts are down recently, so much of this rig count increase seems to represent a re-purposing of rigs.)
Active rigs in North Dakota have also increased greatly. (These rigs are include both oil and natural gas, but with the Bakken and Three Forks-Sanish plays in North Dakota, it seems as though most would be oil rigs.)
There are several reasons why the hoped for increase might not be realized, however. These include:
Inadequate infrastructure. One question is whether inadequate infrastructure will prove to be a roadblock to meeting ambitious production goals in five to 10 years. The AP article quoted above mentions that currently oil is being transported to market by rail and truck, and drilling companies have erected camps for workers. If infrastructure problems are already being reached, before the ramp-up really takes place, a person wonders how much of an obstacle these considerations will be in the future.
Inadequate price. What tends to happen when there isn’t adequate transportation for the oil is the selling price of the oil tends to be depressed, relative to other types. As of February 8, the spot price for Brent was $99.25; the spot price for West Texas Intermediate (WTI) was $85.85, and the spot price for North Dakota Sweet was $65.61. The target discount rate relative to WTI is quoted as being 10% (because it is a light oil), but the actual price seems to be much lower.
It is easy for operators to assume that the price differential will get better, and also that the prices of other types of oil will continue to rise. But all of these things are by no means certain. High oil prices tend to send the economy into recession, so world prices may not rise as much as hoped–they may oscillate instead, rising, then putting the economy into recession and falling again. Also the differential of North Dakota types of crude to Brent may stay low for an extended period, if infrastructure issues cannot be worked out.
Optimism before drilling. There are many unknowns before drilling including how quickly oil production from individual wells will decline, how long wells will prove to be economic, what proportion of wells will have high production, and the level of oil and gas prices in the future. It is natural for those who are trying to get others to invest in these ventures to base their assumptions on an optimistic view of the future. If experience with shale gas in Texas is any clue, once realities start setting in, the level of drilling may decline, and overall production, after an initial run-up, may decline. If this happens, it will be very difficult to meet the ambitious goals presented.
Large amount of increase required. If we look at a graph of countrywide US oil production, it has been decreasing prior to an uptick in 2009 and 2010. Bakken oil production (in ND +MT) is shown near the bottom of Figure 4. It appears as a thin blue line that was a bit thicker back in the late 1980s, became thinner for many years, and now is a bit thicker (reaching an average of about 370,000 barrels a day in 2010). Getting that line, or that line plus some other areas that are only starting up, to increase by 2 million barrels a day, to 2,370,000 per day by 2015, would be a tall order.
Likely other declines at same time. US crude oil production has been headed downward for a long time–actually since 1970, not just since 1985 shown on the graph Figure 4. If overall production is to be increases by 2 million barrels a day by 2015, it will be necessary to overcome these declines, as well as add 2 million barrels a day of new production. What happens is that each year, more and more oil fields and oil wells within oil fields become non-economic. These are closed. Also, what is extracted is an oil-water mix, and the proportion of oil tends to fall over time. This means that if a given volume of oil-water mix is processed from a well, each year the well will yield less oil and more water.
There has been discussion of raising taxes on oil companies. Raising taxes on oil companies tends to raise the number of wells that are non-economic.
According to Figure 5, about 85% of US wells are now producing less than 15 barrels a day, and about 15% of wells are moderate rate wells, producing 15 to 1,600 barrels of oil equivalent a day. Only a small percentage are high rate wells. If tax rates increase, some of them will be closed. New wells will also become less economic, and some wells will not be drilled that would otherwise be drilled. So a person would expect an increase in taxes on oil companies to result in a step down in existing production. Many of the oil companies affected will be small–their only business may be a few wells producing less than 15 barrels a day. The amount of oil produced by so-called stripper wells is about 900,000 barrels a day.
Another area where there is risk of decline is Alaska. The Trans-Alaska Pipeline System is suffering from issues related to low flow and corrosion. Major upgrades to the system may be needed, including heating the line, to keep it operational. At some point, the amount of “fixes” to the Alaska pipeline will exceed the value to be gained from shipping the oil, and the whole system may need to be closed because of low flow. The current flow through the pipeline is 640,000 barrels a day.
3. Can this additional oil supply really reduce the US’s imports by over half, in ten years?
US oil consumption reached its maximum level in 2005. Figure 5 shows a breakdown into its major components.
The crude layer in blue is the same countrywide crude oil production as shown in Figure 4. The purple layer on the top is imports (minus exports), so net imports, based on EIA data. The layer I have called miscellaneous is everything else that goes into what is reported as “liquids.” Recently, the miscellaneous category has been about one-half natural gas liquids, one-quarter ethanol, and one-quarter “refinery gain”–that is the expansion that occurs when the US refines crude oil. The “miscellaneous” items are products that provide less energy per barrel than oil. Many people believe that these additional items have been included in “liquids” figures to make US oil production look like it is performing better than it really is.
Natural gas liquids. I am suspicious that quite a bit of the 2 million barrels a day of additional production by 2015 that is being forecast is not really oil. Instead, I expect it will be natural gas liquids. This currently represents about half of the “miscellaneous” layer in Figure 6. Natural gas liquids (NGLs) include propane, butane, and other gasses. It may very well that much of the recent increase in “oil” drilling rigs is, in fact, primarily for NGLs, since there has been a great deal of recent interest in liquids-rich gasses. In fact, some articles talk about the possibility of falling prices for NGLs, because of a possible supply-demand imbalance, if production of these ramps up.
An increase in NGLs would be of lesser benefit than oil, because it is not directly substitutable for oil, and is a cheaper product. Initially, it would mostly make home heating for those using propane cheaper, but then tend to drive NGL developers out of the market. Unless NGLs can cheaply be converted to higher priced oil products (and refinery capacity can be added quickly to accomplish this), it would seem like a drop in prices would quickly put an end to the NGL ramp-up.
Imports. Figure 7 shows a graph of US net imports–that is the top layer on Figure 6–by themselves. (On all of these graphs, the data for 2010 is through November, but I have estimated December, to give an approximate 2010 value.)
It seems to me that oil imports really depend on what the US can afford for imports–how high the price is, how much oil for export is on the world market (which helps determine the price), and whether the US is in recession because of high oil prices. Oil imports were increasing up until 2005; now they are decreasing. This decrease in oil imports reflects the fact that oil in the world export market peaked in 2005, as much as anything else. High oil prices (and layoffs indirectly related to high oil prices) have made it difficult for people to afford goods and services that require oil in their production (vacation trips, new homes, new cars, many other types of goods). As a result, US demand for oil products has dropped to the point where our imports have dropped each year since 2005.
In my view, if additional US oil is produced, it actually helps increase US demand for oil products–in fact for all products. More people are employed, and this puts more money into the economy. It also helps keep world oil prices from escalating as fast as they would otherwise. The net effect is that I would expect higher US oil production to increase US imports (or maybe, keep imports from falling as fast), because they will help keep the US out of recession. I am sure some will disagree with me on this, however.
US oil imports have declined about 25% in the five years since 2005. In the next ten years, I would expect oil imports to continue to decline, regardless of what we do, because the amount of oil on the world market will continue to drop, and oil importers will tend more and more to be in recession. It is not clear how much US oil imports will drop, but a 50% drop in the next 10 years would not seem all that unlikely, regardless of what we what we produce, because of oil exporting countries will tend to consume more, and more countries will shift from being exporters to importers. We are currently importing 9.4 million barrels a day, so a reduction by half by 2020 would be a reduction of 4.7 million barrels a day.
Responding to the initial assertion that the oil ramp-up will permit a reduction by half of oil imports by 2020. If somehow over the next ten years, we could really produce 4.7 million barrels of oil to offset the decline in oil imports that we will likely be losing because of declines in the world export market, that would be wonderful. But at most, what it looks like the author of the AP article is looking for is a mixture of NGLs and crude oil that might ramp up to 2 million barrels a day by 2015, and 4.7 million barrels a day by 2020, in addition to compensating for whatever other declines we might be encountering.
If the mixture is heavily NGLs, it seems as though refineries will need to be reconfigured to adjust the NGLs to permit reformation into longer-length chains, to make the NGLs truly substitutable for oil. I do not know how feasible such a step would be, or what the “energy cost” would be. It would really be the net oil addition, after the conversion process, that would be of interest.
4. How much of a difference will this oil make to “peak oil”?
It seems to me that whatever additional oil and NGLs are produced will have a much bigger impact on the US economy than it will have on “peak oil.” Adding more energy, if it can be done at a price that is affordable, will be help keep the US out of recession, and thus keep employment up and demand for energy products up.
We have known for a long time that a huge amount of oil is available, in forms that are increasingly difficult to extract. The question, in my view, is how much of this huge amount of oil is economic to extract. This is closely related to Energy Return on Energy Invested (EROEI). At some point, oil becomes too expensive to extract; it just puts the economy into recession, or worse. A schematic diagram of what happens is shown in Figure 8:
We have known about the Bakken oil shale and the many other shales that have NGLs for a long time. There are also many other types of oil that we know about (such as ultra-deepwater, polar, oil-shale) that are quite expensive to extract, both in terms of price in dollars and in terms of resources required. The resources required are not just the direct resources of drilling–they also include pipelines that might not be used for very many years, and even local refineries, which again might not be used for many years, and training for workers. With respect to NGLs, if they are to be used as “regular” oil, they will need unification, perhaps with catalytic reforming, if they are to be used as longer-chain hydrocarbons, which are the higher-priced, more desirable, product. The big question is whether these processes can be made to be economic. If we ever get to the point where more energy is consumed in these processes than we get out at the end, the processes are clearly losers.
To me, each decision to drill a new well, or to start a new field, or even to continue pumping from an existing well, is based on the economics of the day. Some fields or potential wells or new wells drop below the “Non-economic” line on Figure 8, as tax rates rise. Others rise about the non-economic line, as technology improves. But by and large, the vast majority of oil resources that we know about will forever lie below the non-economic line. The assumption that oil prices will rise high enough to allow us to extract all of these oil sources is based on an incomplete understanding of the situation. At some point, the costs (and energy demands) of extraction and processing just become too high, relative to the benefits. Demand can never rise high enough to produce the high prices required for extraction. Ultimately, production will fall, not from a lack of resources, but from inadequate demand for high-priced oil from low quality resources.
The manner in which Figure 8 fits in with Hubbert’s Curve is not directly obvious. Most “liquid” oil will tend to be in the upper “economic” triangle. Most “solid” forms of oil will tend to be in the bottom portion of the triangle. (Hubbert’s Curve is usually applied only to the liquid portion of oil resources.)
But within this general breakdown, the edges will be determined by economics–does it make financial sense to use a particular tertiary recovery method on a particular liquid-oil field? Is it economic to extract something that is not quite liquid oil (like NGLs) and transform it to something that might operate vehicles?
One thing that is definitely different about Figure 8, compared to Hubbert’s Curve, is a different implication regarding how much is left, when the non-economic line is reached. Hubbert’s Curve discussion talks about half of the oil being gone, when decline starts. There is no such implication with Figure 8. Operators will continue to extract oil that can be extracted at low price (high EROI), even as more and more new types of extraction fall below the non-economic line. But it seems quite likely that much less than half of the low-priced (high EROEI) oil will be left, when we start running into difficulties with new oil types falling below the non-economic line.
To me, the big question is whether Bakken oil shale, other oil shales, and all of the additional NGLs can really be made economic. If they can, and the amount of oil extracted raised to the hoped-for 2+ million barrels a day by 2015 and 4.7+ million barrels a day by 2020, the new oil sources may help to keep recession away for a while longer. But if not, we are likely nearing the point where limited oil supply will push us more and more into recession. I am doubtful that the new oil shale sources can ramp up as quickly as hoped, but there is at least some glimmer of hope that these fuels will help keep the day of reckoning away a bit longer.
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As "The Rock" and I have both noted, the Austin Chalk in Texas is a pretty good model for the various oil shale plays, and regarding claims being made by the oil shale promoters, at the peak of the Austin Chalk horizontal drilling boom a lot of similar claims were being made by Austin Chalk promoters.
And of course, the oil shales in Colorado, which are kerogen deposits in the Green River Formation (a substance that must be "cooked" to produce a liquid for refining), are not the same thing as the thermally mature oils in the Bakken and Eagle Ford, which can be shipped directly to refineries.
This isn't the stuff that needs to be "cooked" that I am talking about. I am talking about the stuff that needs to be "fracked", like the Bakken Shale. It looks like the Natural Gas Liquids are being dumped into this category too, but they too need to be fracked.
As a petroleum geologist, the distinction between thermally mature oil in the Bakken, et al, and kerogen deposits is clear to me, but the distinction is not apparent to a lot of people, e.g., talking heads on CNBC, so I would suggest that any articles on oil from shales* should have an explanation about thermally mature oils versus kerogen deposits.
*Of course, the Green River formation in Colorado is really mostly an ancient lacustrine marl deposit
Mature v immature source rock?
Exactly. The marlstone is undercooked so the kerogen hasn't turned into oil. Just give it another 60 million years or so, maybe pile a few mountains on top to speed things up. Heavy oil (bitumen), like in Athabasca, is overcooked (the lighter fractions have escaped).
Ahhh..."Just give it another 60 million years or so, maybe pile a few mountains on top to speed things up."
Almost verbatim from the 1976 remake of "King Kong", where the oil geologist for Petrox Corp, Roy Bagley, (played by Rene Auberjonois) drunkenly tells Fred Wilson, (Charles Grodin) that the oil they've discovered on Skull Island (or whatever it is called) would, indeed, be a huge find...after ten thousand years! That was one of the more hilarious scenes of the film. And now it's being played out in real life.
-sTv
FWIW I agree. There is a lack of geology over here that could be addressed perhaps by "technical talks" or some such. There are lots of interesting socio-economic charts and graphs, but howabout some rocks, dirt and oil sometime? Thank you dearly, Westexas for being here. What happened to FF (FractionalFlow?)
~:)
Great article! Here are the quick and easy answers:
1. Is this really a new drilling technique? NO.
2. How likely is the 2 million barrels a day of new production, and the 20% increase in US production, by 2015? NO CHANCE. Production will decline by 20%.
3. Can this additional oil supply really reduce the US’s imports by over half? NO CHANCE.
4. How much of a difference will this oil make to “peak oil”? NONE Whatsoever. Declines will still outpace new production.
What to think about this ? A spokesman (on video, posted about 1 week ago on Drumbeat) who claimed that oil shale in the Green River formation is economical with $30 oil, said that the oil won from shale can be used directly, because it doesn't need refinery.
...claimed that oil shale in the Green River formation is economical with $30 oil, said that the oil won from shale can be used directly, because it doesn't need refinery.
That's very funny, considering that operating costs in established oil sands plants in the Athabasca Oil Sands run around $45 per barrel, and oil sands are a lot easier to produce than oil shale.
I think he's blowing smoke. More likely the costs would be 400-500% higher. We don't know, because nobody has a working pilot plant yet. I suppose ignorance is bliss, you can pick any number out of the air you want to.
Oil from shale can be used directly? What is he going to do, smear it all over his car?
Rocky, clearly he was suggesting that it will produce 'different kind of carbon chains'. So he is blowing smoke in many ways, probably one with THC.
Well, oil shale has been used "directly" in a few places by burning it like coal. However, the oil shale in places like Estonia is close to the surface, not buried 2000 feet under rock like it is in much of the Green River formation.
Any discussion of doing *anything* with the oil shale in Colorado/Utah has to start with the lack of water, and end with the lack of water, and in between you can talk about the lack of electrical resources. The area has a total population of maybe 200,000 spread over tens of thousands of square miles, so there is not a lot of electrical generation in the area currently. A nuclear plant has been whispered about in the town of Green River, Utah to supply power to shale projects, but of course, the water issue rears its ugly head again. The 50,000 acre feet per year of water is there in the Green River to build a plant, but every drop used upstream of Arizona, Nevada and California means less water for the megalopolises and farms of those states.
There is going to be one heck of a collision between the water needs of the Southwestern US and the energy needs of the rest of the US if there ever is a large scale attempt to produce oil from the rocks in Colorado and Utah.
@whomever, the word kerosene directly comes from the word kerogen. In ye olde days in Scotland they called it kerosene shale, not oil shale. 150 yrs ago, no one wanted that nasty olde gasoline, it was an unfortunate byproduct of the simplified oil refining done then. Everyone wanted that nice white kerosene (that came from kerosene shale/oil shale) to use in their lamps instead of that expensive whale oil. The Shell ICP process claimed semi-refined output including near-diesel, don't know about your quoted person. There was a long thread on this last week with some links but it all got removed after I'd skimmed it when I came back for a longer look-see. Or perhaps I imagined it?
It's hard to see how this can make much difference to us oileating minnows, considering the fact that we are trapped between the sharks of depletion and the bluefish of export land.
I frequently use the example of the North Sea, which had an absolute crude oil production peak of about six mbpd in 1999. Sam Foucher found that oil fields whose first full year of production was 1999 or later had their own peak in 2005, at about one mbpd, which was equivalent to about one-sixth of total regional production in 1999. However, these post-peak fields only served to slow the overall decline in the 1999 to 2009 time period to about 5%/year.
We have seen something similar globally, as global annual crude oil production (C+C) has so far failed to exceed the 2005 annual production rate--despite oil prices exceeding the 2005 annual level of $57 for going on six years now, with five of the six years apparently showing year over year increases in annual oil prices. The difference between the North Sea and global production is that we have a slowly increasing unconventional global component.
Note that based on the HL models, the world in 2005 was at about the same stage of conventional crude oil depletion as the North Sea in 1999 (approximately 50% depleted in both cases).
But as you noted, then there is the net export situation. . .
How much oil is in place in those shales, and how much can be recovered using current technology and prices? Does anybody know?
There is a big question as to how much "fracking" can release, and even how long existing wells will produce at economic levels. You see huge numbers and small ones.
I know that Douglas Westwood consulting firm is expecting that shale oils like Bakken and Natural Gas Liquids will grow greatly. I have a post giving my summary with my comments of a presentation by Steven Kopits up on Our Finite World now.
This is what his (probably optimistic) forecast of US production looks like going forward:
Gail,
These layered color coded graphs are useless. To understand this one I had to enlarge multiple times. I am not color blind. Being a pilot I am tested regularly. Gail, please do what you can to discourage this form of data presentation.
cheers Juan GA.
With those graphs it strikes me that always they manage to keep production rising. EIA, etc projects what the world will need, and with that data they draw the graphs.
I don't care how much oil is in oil shale. That's all I ever read about. One or two trillion barrels of oil, most of which is not economic..., I want to know production rates. That's what matters to me.
(correct me if I'm wrong -- I'm just a peak oil groupie)
The U.S. consumes about 20 million barrels of oil a day.
The world consumes about 80 million barrels of oil a day.
Current Canadian oil production is about 3 million barrels of oil per day. 40% of it comes from tar sands.
Royal Dutch Shell's Mahogany Ridge project (a demonstration project)
produced 1,400 barrels of oil from shale in Situ
Whatever oil we get from fracking oil shale
I do not know how much oil we get from Shale Oil in total but I know it's marginal.... (less than tar sands by far)
Plus, net energy will be lower for tar sands and oil shale (especially oil shale)
Canadian oil production is, in fact, running at about 3 million barrels of oil per day, but 55% of it is now from oil sands.
USGS 2008:
Cumulative Bakken production of 135 MMBO 1953-2008
~36 MMBO for 2008 alone
Mean Estimated ultimate recoverable of 3.65 Billion Bbls of 413 Billion Bbls in place (<1% recovery) with "current technology."
MRO 2011 press release:
MRO estimates that its average well will cost from $5.5 million to $6.5 million, and produce an average of 300 to 500 BOE per day during the first thirty days. The average well will have an estimated ultimate recovery of 350,000 BOE per well. That's about $17/bbl just for the drilling.
With MRO's numbers, you need over 10,000 wells to produce USGS 3.65 BBO at a drilling cost of $60 billion. Of course that's only 65 wells per active rig. I wonder what the peak rate will be? How fast can those wells be drilled? Will recovery efficiency improve or are current estimates optimistic?
For comparison, a good deepwater well might cum >20 mmbo with rates over 20,000 bopd. Of course the well cost is also x20, not to mention platform and pipeline costs.
Which tells me it may be worth to lay a pipeline from these shale areas to Wisconsin and Illionois, to move the crude out in large volumes. If the total resource is 3.65 to 7.3 billion (I doubled the estimate just in case), the peak rate would be about 1 million barrels per day. So it looks like a 40-42 inch pipeline could make money - it's actual capacity would set the plateau rate for the region.
I've worked planning mega developments for very large oil volumes from remote areas, and eventually one has to settle on a transport system to carry a decent amount of crude, but which also has a reasonable life span.
In this case, the pipelines will set the plateau, although some oil will leak out by train and truck, I imagine. But if the industry is rational, they'll get together and encourage construction of something able to carry about 1 million bpd, and that's as far as it'll go. And they will have to commit throughput or back it with equity. Which means if the wells don't pan out the pipeline(s) will be a white elephant.
Conclusion? This North Dakota oil shale play won't go above 1 million BPD, say by 2020.
Interesting calculation!
The sum of all of the optimistic statements being given to investors likely isn't true.
Currently there is less oil pipeline capacity moving out of the area than the oil that is shipped. Trains are being used to move oil out.
http://nextbigfuture.com/2011/02/north-dakota-oil-might-head-to-over-one...
(Harold Hamm/Continental Resources, CEO) "In total development in the Bakken we see about 48000 wells, of which 90-percent are yet to be drilled." Oil tycoon Harold Hamm says the formations in North Dakota and Montana hold about 20 billion barrels of recoverable crude. There are about 170 rigs drilling in North Dakota and oil tycoon Harold Hamm says that number is expected to rise. Hamm estimates those 48000 wells will produce as much as 1,000,000 barrels a day and it may be just a tad more than that.
http://nextbigfuture.com/2011/01/estimates-of-north-dakotas-oil.html
Gail does not address that there are potentially huge shale gas discoveries in Argentina, Quebec, Poland, India, the UK, off the coast of Israel, in China, British Columbia. There are potentially huge oil shale in Australia, China and France. There has not been any mention yet but I suspect large oil shale will be found in Russia as well.
The Arthur Creek shale formation in the Southern Georgina (Australia) is very similar to the Bakken but with about 5 times the thickness. All 18 exploratory wells drilled so far have shown oil. Australian geologists certainly seem to think they have found another Bakken. In another 15 to 18 months we will know if this is indeed true.
It is not Australia, however, but France-- where the greatest industry anticipation and activity is building in the search for the next Bakken; in the well known Paris basin.
The Paris basin (current production of less than 15,000 bpd of conventional oil) covers the northern half of France and extends into neighboring countries. It is a vintage oil and gas basin. Over 2 thousand wells have been drilled and 52 fields discovered. It has extensive oil and gas shale deposits. The 3 oil shale formations are the Lower Lias , Amaltheus and Schistes Carton. The current focus of excitement is the Lower Lias with estimated oil in place resource base of a few billion to tens of billions of barrels. The estimates (guesses) for the oil in place in the other 2 formations are much higher.
Torreador Resources asserts that an estimated 100 billion barrels of oil have been generated from source rocks in the Paris basin, of which 30 billion are in the Lower Lias.
In addition to the Paris Basin, Hess thinks it has found a basin analogous to the Bakken in China.
There are potentially huge shale gas discoveries in Argentina, Quebec, Poland, India, the UK, off the coast of Israel, in China, British Columbia.
Advancednano, I had the weekend to chew over this some more. If the shale play in North Dakota is for real, and the companies involved convince themselves it's not a flash in the pan, then pipelines should be built. I've spent most of my career overseas, so I'm a bit off when it comes to the hodge podge way things are done in the US, but evidently shipping by pipeline is much cheaper than shipping by train.
Let's say a shipper sees $15 per barrel higher tariff shipping by rail, then a pipeline is definitely viable. The question is, how large should it be? This depends on the commitments shippers are willing to make. And the shippers don't want to commit until they understand the way these rocks behave. So my guess is, since they're already moving a lot of oil by rail, somebody will build a smallish pipeline, then other lines will eventually be built to replace the trains - if the play pans out. Shipping by rail year after year just doesn't make economic sense.
The same thing will hapen in new areas, I think. They'll have to run pilot production for several years before they convince themselves to put in lines. I suggest those who work out the overall supply/demand balance for peak oil estimates take this into account, when the industry isn't sure about reservoir behavior, it tends to take it slow when it comes to transportation systems from remote areas.
If the shale play in North Dakota is for real, and the companies involved convince themselves it's not a flash in the pan, then pipelines should be built.
The Bakken play is for real and the pipelines are already under construction:
Bakken Pipeline Project
Mind you, this is a Canadian pipeline company pipelining North Dakota oil into Canada and putting it into the Canadian export pipeline system, which has seen massive expansions in recent years.
The Portal Link system used to take oil from Saskatchewan into North Dakota - they are just reactivating it and reversing it to run the other direction.
i know almost nothing about the local transport system. But if the proposed 1 million bpd is the target, then they need a lot more pipeline capacity. I would call a 125,000 b/d line a test or pilot system. A more significant investment would be say something to move 400,000 BPD. And those take time.
the pipeline companies wait until they have commitments from oil companies for about 80% of the capacity, then they build the pipeline. This is starting to happen. There is a lag in the construction of pipeline to the oil produced in a growing set of oil fields.
Transcanada pipeline is expanding pipeline capacity as well.
http://www.transcanada.com/5631.html
http://www.transcanada.com/bakken.html
In the fall of 2010, TransCanada went to the market with a proposal to move Bakken crude oil production by constructing a receipt facility at Baker, Montana. The open season was successful, allowing TransCanada to sign firm term contracts for 65,000 bpd of crude oil transportation from the Bakken to key U.S. refining markets.
The Bakken Marketlink project will provide receipt facilities to transport up to 100,000 bpd of crude oil from the Williston Basin producing region in North Dakota and Montana, to Cushing, Oklahoma and the U.S. Gulf Coast using facilities that make up part of the Keystone Gulf Coast Expansion Project. The project is expected to be in service in 2013.
Cushing Marketlink Project
In the fall of 2010, TransCanada went to the market with a proposal to move crude oil from the prolific Cushing crude oil storage hub in Oklahoma, to markets on the U.S. Gulf Coast. The open season was successful, allowing TransCanada to move forward with this important project.
The Cushing Marketlink project will provide receipt facilities to transport up to 150,000 bpd of crude oil from Cushing, Oklahoma to the U.S. Gulf Coast using facilities that make up part of the Keystone Gulf Coast Expansion Project. The project is expected to be in service in 2013.
Keystone Pipeline Project
The U.S. $12 billion Keystone pipeline system will play an important role in linking a secure and growing supply of Canadian crude oil with the largest refining markets in the United States, significantly improving North American security supply.
On June 30, 2010, TransCanada commenced commercial operation of the first phase of the Keystone Pipeline System. Keystone's first phase was highlighted by the conversion of natural gas pipeline to crude oil pipeline and construction of an innovative bullet line that brings the crude oil non-stop from Canada to market hubs in the U.S. Midwest.
Keystone Cushing (Phase II) is an extension of the Keystone Pipeline from Steele City, Nebraska to Cushing, Oklahoma. The 36-inch pipeline is currently under construction and will connect to storage and distribution facilities at Cushing, a major crude oil marketing/refining and pipeline hub.
The proposed Keystone Gulf Coast Expansion Project is an approximate 2,673-kilometre (1,661-mile), 36-inch crude oil pipeline that would begin at Hardisty, Alberta and extend southeast through Saskatchewan, Montana, South Dakota and Nebraska. It would incorporate a portion of the Keystone Pipeline (Phase II) through Nebraska and Kansas to serve markets at Cushing, Oklahoma before continuing through Oklahoma to a delivery point near existing terminals in Nederland, Texas to serve the Port Arthur, Texas marketplace.
Found this while looking for info on the Monterey formation: How Much Oil Does the U.S. Have in the Ground - What Does It Mean for Investors? - Seeking Alpha
Well, there's an alternate interpretation as well. I remember arguing about the Bakken a lot starting 4 years ago - all the companies and Price had these sky's-the-limit estimates, and the gung ho contingent were altogether crestfallen by the USGS figure, of course. They were also ready with plans for extreme EOR to wring every last barrel out of the thing, and the Seeking Alpha guy recounts more of these in his piece - CO2 and waterfloods to recover 16 bbo etc. Uh huh. The dead giveaway is the rig count in Gail's article; this is what's called a "brute force approach."
TX production is still flat, from tapping of Permian basin leftovers. Lots of dinky lenses to drill. This too is mopping up; Hirsch could have thrown this approach in as a wedge in his study; or perhaps it's part of EOR by his definition.
There doesn't seem to be much going on in CA and the Monterey oil rigs all are operating in the San Joaquin doing developmental drilling. Penn Energy is ready to redrill some 80s wildcat. It's an odd formation, acts as both source and reservoir, from Miocene sediments. Meanwhile CA just continues on its inexorable decline.
Heading Out had a blog post about the Eagle Ford, a play that's great if you think we'll achieve energy independence by commuting on forklifts burning C3H8. OGPSS-When oil isn’t crude and gas isn’t gas, the Eagle Ford Shale play.
And the USGS estimates are almost certainly wrong(too low). While Gail is correct in stating that directional drilling or fracking individually are not a new techniques, to say that there has not been a breakthrough in drilling technique in the last few years is also incorrect. It is the simultaneous employment of directional/horizontal drilling and multi-stage fracking that has been an innovation in drilling technique for oil E&P that has changed the EUR and economics of many different formations in just the last 5 years or so. Additionally, there has been considerable innovation in fracking methods (swell packers, Perf and Plug processes, ceramic proppants, etc) and 3D/4D seismic imaging and microseismic monitoring that have led to the impressive production growth rate (2000-2005 daily production average 87Mbbl/day vs 2010 average of 309Mbbl/day and current average north of 350Mbbl/day. Monthly production hit 4MMbbl at the end of 2007 and is now at about 10.7MMbbl and climbing rapidly).
Also, when you look at Bakken production in the last couple of years from individual companies, like BEXP for example, you'd see that the E&Ps also moved from short laterals and single stage fracking to long laterals and 475' spacing, to 400' spacing, on down to the current trend of 250' spacing with the number of frac stages generally in the range of 25-35. As the number of frac stages has increased and the spacing has decreased, recovery rates have consistently improved. Additionally, there seems to be considerable evidence to suggest that the Bakken and the Three Forks/Sanish formations are separate and do not communicate with each other. If true, this too means the USGS survey estimate is too low.
Why would the formations being separate affect the overall OOIP? I see Durgen asked USGS to reevaluate the formation(s) before leaving the Senate. And in any case I'm just questioning the companies' integrity; of course they would play up the riches of a resource, they're fishing for investment $$$$. Third parties should be the ones to do an on-the-level assessment of what's there.
All that extra fracking adds to the cost, of course. Looking at the Baker Hughes data I see that vert/horz wells as a % of the total achieved parity in 2009 and the majority by far are now horz. Perhaps the drillers will hit a sweet spot in terms of economics where the rates will plateau.
And in any case the Bakken doesn't have much impact on the world at large. Perhaps if the various theorized Bakkens around the world that advancednano posts about materialize into commercial production we'll see something. Right now ND mostly seems to be having an impact in distorting WTI badly.
Thanks for the article, Gail. Always a pleasure reading your insights.
As for the whole situation, I think we will increasingly see these magic bullet-esque attempts from the MSM as the situation gets worse and worse(and more obvious) to drum up, as you put it, 'the last glimmer of hope'.
All the experts, genuine experts, like Skrebowski, Hirsch, Aleklett, Robelius and others who are understanding the situation very well, point at the 2008-2015 range(depending how you count) on when we'll hit Peak(and how that's counted is a bit individual as well).
Hirch's 2012-2015 is still the best bet from this viewpoint.
There is one factor I think people forget though, and it's the "X-factor".
In the last 2-3 months we've seen what has happened when oil goes into the volatile area and general instability ensues, you get a Libyan revolution.
Ultimately what will decide Peak Oil is not geology but geopolitics, and often uncalculated and randomized, as we've seen. A sudden war, revolution or somekind of conflict. It can also be sparked by food prices which has fuelled the current unrest.
At this point it makes less and less sense of trying to pinpoint the Peak geologically, we can only point in a general direction, a windowed frame.
If will be 2011 or as late as 2015 will depend on things nobody can possibly forsee. Who could have forseen Libya at the start of this year?
From now on we're into the dark.
Given that Libya is increasingly looking to be entering a stalemated civil war, we can forget most of their production for the next few years. And it was easy, light sweet quality oil.
This I think will be typical of the reaction to peak oil - political instability as the oil rich monarchies and dictatorships fail to keep their young, restive and rapidly growing and increasingly hungry and religiously radicalised populations under control.
Decline from the peak will not be a smooth geological curve. It will not be an economic event. It will be violent and explosive.
A lot of people will die.
The esteemed (by us) geologists and economists posting here will have all their predictions rapidly overtaken by events.
I agree with you RalphW -- human history already tells us that doesn't it?--Great article Gail--maybe it's time a simliar report is done on uranium?
You should probably do that report yourself. I think Gail's too honest.
I did do a report on uranium a couple of years ago, and also a more recent update, which includes this graph:
I think one of the issues is that it is hard to get the price of uranium up high enough, long enough, to really go after additional supply. Also, the recent historical pattern is toward less electricity generated using uranium, rather than more. Many of the old reactors are nearing the ends of their lives, and countries are not taking steps to replace them.
There are long lag times in all of this as well. I would have to look at it some more, but even then I am not sure I would have all the answers.
What is missing is the real resource triangle for Uranium, which puts the one for oil to shame.
Uranium disperses a huge amount, by concentration levels you get the following:
Very high-grade ore (Canada) - 20% U 200,000 ppm U
High-grade ore - 2% U, 20,000 ppm U
Low-grade ore - 0.1% U, 1,000 ppm U
Very low-grade ore - 0.01% U 100 ppm U
Granite 4-5 ppm U
Sedimentary rock 2 ppm U
Earth's continental crust (av) 2.8 ppm U
Seawater 0.003 ppm U
The amount of uranium dispersed in the crust and ocean is much, much greater than that in the richest deposits.
So us going after shale oil or worse is a lot like us going after low-grade forms of uranium.
Time for another update.
Nuclear power generation was back up to the 2630-2650 TWH range in 2010.
http://nextbigfuture.com/2011/02/world-nuclear-generation-in-2010.html
This is back near the peak of nuclear generation as calculated by the World Nuclear Association (WNA).
The WNA reported 2008 world nuclear generation at 2601 TWH and 2009 at 2558 TWH.
2007 had world nuclear generation of 2608 TWH and 2006 had 2658 TWH per the World Nuclear Association.
The IEA is about 120 TWH more than the WNA numbers, and I would guess that they are including the nuclear generation from submarines and aircraft carriers and other non-commercial nuclear power.
The IEA reports 2008 world nuclear generation at 2731 TWH
The IEA reports 2007 world nuclear generation at 2719 TWH and World generation 2006 at 2793 TWH
http://nextbigfuture.com/2010/12/average-capacity-factor-for-nuclear.html
Spain not shutting down their reactors.
also new nuclear power coming online
Plus the list below does not include the surge of reactor orders when China starts exporting in 2013 at far lower prices. Those new reactor orders will have a big impact from 2019+ as those reactors start finishing
2011 Russia, Energoatom Kalinin 4 PWR 950 [probably 2012-2013]
2011 Taiwan Power Lungmen 1 ABWR 1300
2011 Canada, Bruce Pwr Bruce A1 PHWR 769 [probably 2012]
2011 Canada, Bruce Pwr Bruce A2 PHWR 769 [probably 2012]
2011 Pakistan, PAEC Chashma 2 PWR 300
2012 Finland, TVO Olkilouto 3 PWR 1600
2012 China, CNNC Qinshan phase II-4 PWR 650
2012 Taiwan Power Lungmen 2 ABWR 1300
2012 Korea, KHNP Shin Wolsong 1 PWR 1000
2012 Canada, NB Power Point Lepreau 1 PHWR 635
2012 France, EdF Flamanville 3 PWR 1630 [probably 2014]
2012 Russia, Energoatom Vilyuchinsk PWR x 2 70
2012 Russia, Energoatom Novovoronezh II-1 PWR 1070
2012 Slovakia, SE Mochovce 3 PWR 440
2012 China, CGNPC Hongyanhe 1 PWR 1080
2012 China, CGNPC Ningde 1 PWR 1080
2013 Korea, KHNP Shin Wolsong 2 PWR 1000
2013 USA, TVA Watts Bar 2 PWR 1180
2013 Russia, Energoatom Leningrad II-1 PWR 1070
2013 Korea, KHNP Shin-Kori 3 PWR 1350
2013 China, CNNC Sanmen 1 PWR 1250
2013 China, CGNPC Ningde 2 PWR 1080
2013 China, CGNPC Yangjiang 1 PWR 1080
2013 China, CGNPC Taishan 1 PWR 1700
2013 China, CNNC Fangjiashan 1 PWR 1080
2013 China, CNNC Fuqing 1 PWR 1080
2013 China, CGNPC Hongyanhe 2 PWR 1080
2013 Slovakia, SE Mochovce 4 PWR 440
2014 China, CNNC Sanmen 2 PWR 1250
2014 China, CPI Haiyang 1 PWR 1250
2014 China, CGNPC Ningde 3 PWR 1080
2014 China, CGNPC Hongyanhe 3 PWR 1080
2014 China, CGNPC Hongyanhe 4 PWR 1080
2015 China, CGNPC Yangjiang 2 PWR 1080
2014 China, CNNC Fangjiashan 2 PWR 1080
2014 China, CNNC Fuqing 2 PWR 1080
2014 China, CNNC Changiang 1 PWR 650
2014 China, China Huaneng Shidaowan HTR 200
2014 Korea, KHNP Shin-Kori 4 PWR 1350
2014 Japan, Tepco Fukishima I-7 ABWR 1380
2014 Japan, EPDC/J Power Ohma ABWR 1350
2014 Russia, Energoatom Rostov 3 PWR 1070
2014 Russia, Energoatom Beloyarsk 4 FNR 750
2015 Japan, Tepco Fukishima I-8 ABWR 1380
2015 China, CGNPC Yangjiang 3 PWR 1080
2015 China, CPI Haiyang 2 PWR 1250
2015 China, CGNPC Taishan 2 PWR 1700
2015 China, CGNPC Ningde 4 PWR 1080
2015 China, CGNPC Hongyanhe 5 PWR 1080
2015 China, CGNPC Fangchenggang 1 PWR 1080
2015 China, CNNC Changiang 2 PWR 650
2015 China, CNNC Hongshiding 1 PWR 1080
2015 China, CNNC Taohuajiang 1 PWR 1250
2015 China, CNNC Fuqing 3 PWR 1080
2015 Korea, KHNP Shin-Ulchin 1 PWR 1350
2015 Japan, Tepco Higashidori 1 ABWR 1385
2015 Japan, Chugoku Kaminoseki 1 ABWR 1373
2015 India, NPCIL Kakrapar 3 PHWR 640
2015 Bulgaria, NEK Belene 1 PWR 1000
2016 Korea, KHNP Shin-Ulchin 2 PWR 1350
2016 Romania, SNN Cernavoda 3 PHWR 655
2016 Russia, Energoatom Novovoronezh II-2 PWR 1070
2016 Russia, Energoatom Leningrad II-2 PWR 1200
2016 Russia, Energoatom Rostov 4 PWR 1200
2016 Russia, Energoatom Baltic 1 PWR 1200
2016 Russia, Energoatom Seversk 1 PWR 1200
2016 Ukraine, Energoatom Khmelnitsky 3 PWR 1000
2016 India, NPCIL Kakrapar 4 PHWR 640
2016 India, NPCIL Rajasthan 7 PHWR 640
2016 China, several
2017 Russia, Energoatom Leningrad II-3 PWR 1200
2017 Ukraine, Energoatom Khmelnitsky 4 PWR 1000
2017 India, NPCIL Rajasthan 8 PHWR 640
2017 Romania, SNN Cernavoda 4 PHWR 655
2017 China, several
The market is fully supplied; even lifting the embargo on India didn't budge prices much.
The USA has around 700,000 tons of depleted UF6 in inventory (over 470,000 tons of elemental U). That's not reserves, that's inventory left over from enrichment since the Manhattan project. There is also about 60,000 tons of uranium in spent fuel, mostly from LWRs. All uranium is feedstock for fast breeder reactors, and that inventory alone is sufficient to run the USA at ~100 quads/yr for several hundred years.
That's why the Integral Fast Reactor had to die: it would have killed fossil fuels and "green" energy with one stroke. It also requires about 1/10 the steel and concrete of sources like wind, making it more economical if political factors don't torpedo it.
That's politics. Uranium remains a bargain, energy-wise (and the major supply-side response to AGW).
You should know this, but you're in deep denial.
E- Poet, it's about the big picture. What does the tremendous increase of nuclear powerplants tell you ? That they are expecting that the strongly growing middle class in China and India will continue to grow this and the coming decades. That means growing oildemand. Now look at the export maths of westexas and you know how much oil will be left over then to export to Europe, the U.S., etc. In other words, that growth scenario is impossible.
Chindia are net importers, like the USA. The situations are similar.
Chindia do NOT have the nuclear-phobic lobbies which afflict the USA. They (esp. China) are building out nuclear capacity at a staggering rate; China is the major market for the new AP-1000 PWR. India, faced with a uranium embargo because of its development of nuclear weaponry (it has nuclear-armed China on its border), has been investigating thorium. Both have research programs pushing harder than our laggard efforts in the USA (forget England).
Nuclear power does not (now) compete directly with oil. Nuclear generates electricity, and the vast bulk of the USA's oil-fired electric generation shut down more than 2 decades ago. But ground transport is going electric, and some Gen IV nuclear technologies will be able to serve as process-heat sources for chemical reactions. It's certainly possible for nuclear power to bite further into oil's market share... if the liars who practice the politics of fear and barratry don't block it yet again.
What I see happening with these revolutions makes me seriously question the "religiously radicalised" part. It looks like a secular driven revolt. Desire for democracy, a better distribution of opportunity, and above a need to feel respected seems to be the driving force. Outside of a few areas -especially Pakistan, and Afghanistan (not in MENA) these folks seems only mildly religious to me. I think the radical Islam thing was mainly a desperate attempt to find a way out, as other methods had had no success freeing these people. Now, they have examples of seemingly successful secular revolutions. [I say seemingly, because chasing out the old regimes is the easy part, and as long as the current chaos continues the economies of these countries are slipping backwards.]
The International community is not going to let a civil war get in the way of Libyan oil field production. A no fly zone, ships to protect foreign oil company workers and arming the rebels to the teeth to take Gadaffi out of the equation will all come online to make the black gold flow again.
Add Saudi Arabia, Iran and Iraq to the category of 'Libyas in waiting'. The situation in Bahrain puts KSA in the crosshairs. Bahrain cannot afford to liberalize otherwise KSA's Shiites will demand the same treatment. A Bahraini crackdown triggers a Shia revolt in Saudia's oil producing region.
Twitter is buzzing with grassroots revolutionary defiance in Iran. It is fair to say that that country will boil over soon enough.
The non- OPEC oil producing regions are not stable, either. Success of revolution in Egypt lights the path for revolutionaries in Central Asia and Southern Africa. A people- power revolt in Nigeria gains what decades of militant activity could not at the cost to the West of lower net output.
As is seen in Libya, governments which decide to meet unrest with military force presses net output to zero.
OECD policy has been the flip side of net exports. 'Empty suit' dictators with Western support have constrained demand by monopolizing business activities and development. Elites benefit, the greater publics languish and surplus demand is exported to clients who provide military aid and access to Western finance.
The alternative to dictators are the jihadis and other religious autocrats who also constrain demand to the minimum and export the balance to the west. A bare minimum of domestic development is tolerated but demand is not permitted to flower. This leaves the bulk of producing nations' populations too poor to purchase western life- styles and fuel consumption.
When autocrats fail, factions are enabled and nations become 'failed states'. The end result is the destruction of domestic demand while energy producing infrastructure is maintained. The models are Iraq, Myanmar, Nigeria and to some degree Mexico. Failed states do not have to produce resources: Somalia, Afghanistan, Pakistan, Haiti, Yemen export their demand the same as do Iran and Syria. Failed states 'solve' the net export dilemma.
Next on the imperial agenda are Venezuela and Libya. The UK already has commandos on the ground in Libya training and arming the 'rebel' faction. Who will win the war between rebels and Qaddafi? Nobody, that is the intention. The commandos will secure the oil infrastructure and the citizens will be reduced to killing each other for scraps of food. Domestic demand will fall to zero and the 1.5 million barrels per day of Libyan crude will flow toward precious US SUVs and giant pickup trucks.
The danger is that infrastructure cannot be protected before anarchy makes oil business too hazardous to pursue as has been the case in parts of Iraq. A 'people- power' revolution in Iraq becomes another roadblock to the hoped- for 12 million barrel per day production advertised only a few short months ago.
The 'answer' to the US 'Peak Oil' is the overthrow of the Venezuelan government and installation of an American puppet or the creation of a failed state. Venezuela's vast reserves, second only to Saudia's, would replace imports from elsewhere faster than supplies can be had from Bakken. Creating a Haiti where Venezuela now stands would moot net export issues. US forces are already active in neighboring 'friendly' Colombia.
All that is needed is a people- power 'Twitter Revolution' in Caracas. Anyone out there paying attention?
???
Success of revolution in Egypt lights the path for revolutionaries in Central Asia and Southern Africa
So if the Libyan revolution drags on for months and maybe more-Gaddafi may really feel he has nothing to lose by sticking it out to the dire end--will the movement lose steam? I'm sure 'resources' around the globe are trying to fathom that as we type. If the Libya's oil infrastructure gets hammered but the regional movement stalls as the news Libyans' of increased suffering Twitters out around the globe for months on end will the heat begin to dissipate?
Will the movement lose steam?
I don't think so because it is 'do or die' for the revolutionaries. They lose to the Qaddafis and they get rounded up and shot.
It's the same for the dictators. They have one shot to 'get things right' then the failure -- of the brutal ones -- is met at the end of a rope.
It seems the revolutionaries are becoming more determined. Most places have been under the boot for decades, this following decades under brutal colonial regimes. Plus, so far the revolutions have all been successful. The powers- that- be have no clear winning strategy which is why the Saudis are paying off while the Iranians are mobilizing the Basij. Nobody knows what works except for the revolutionaries who know persistence and a shutdown of economies works.
War works too. This is the real problem. When people stop marching and occupying squares there will be more fighter jets, armor and naval operations. Commandos are already at work. Once the heavy stuff gets involved there will be no turning back.
steve
My point is that all remains fluid--persistence is a relative term. Tunisia' dictator fell in a Twitter second, Mubarak went out a little slower more like a blog thread hour. Gaddafi...not sure yet, it hangs in the balance.
from Aljazeera today
She also said there was no optimism there following news of the ultimatum from the rebels.
"There is no more euphoria of a revolution," she said.
"People are worried it will move towards civil war which will continue for months on end. There is a realisation that there is no institution in this country - that you have to avoid chaos.
The Libyan revolution is only three weeks old--but it's the average Joe and Josephine that have bare cupboards, no work income and losses in their family. Persistence may have to go beyond how the word is defined in a cell phone/internet time frame.
Then you have the outcomes. Yes, Mubarak is out but the army is back in control--not a situation many westerners would consider optimum in their own countries.
Libya...the longer the battle drags on the more likely heavy vendetta in the future. Even the smoothest of transitions could border on chaos--there really isn't a national government or military that is organized beyond what Gaddafi kept under tight personal control. There may well be substantial regional and tribal power struggles in the hierarchy vaccuum Gaddafi's family's departure will leave. Not pretty.
What happens it Libya could cool the Twitter fires some--we will see. If it does the powers in place may get just a bit of breathing room to try and improve their countries situations, though I am certainly not holding my breath on their managing that trick even if they get the chance.
I agree with you, that geopolitics is going to play a big role. Our whole system is so tightly networked, that a spike in prices could cause huge disruption (rising inflation, loan defaults, rising food prices) and these in turn could cause the overthrow of governments. In a way, what we are seeing is really the kind of complex interactions foreseen by Limits to Growth analysts years ago. I don't think we can expect a nice downward slope that can easily be fixed by being more efficient in our oil use. It is hard to predict precisely what will happen, expect that the general direction looks to be "down".
Yair...if any good can come out of the present Middle East situation I reckon it would be a few temporory fuel shortages (particularly in Australia and the US) that may help to clarify the thinking...if you like, a portent of things to come a few years down the track.
As I have mentioned before I post on heavy equipment boards and, for a sector that depends on diesel fuel for its existance, the ignorance of the world oil situation is alarming.
Given that the US is the "swing consumer," it could single handedly ameliorate peak oil by setting a national policy to reduce per capita oil consumption down to European levels. The first thing that needs to be done is to make our transportation system as efficient as possible, eg: I think it's criminal that gasoline taxes are as low as they are.
Unfortunately we are outnumbered 1000 (at least) to 1 by people who think it's criminal that gasoline taxes (prices etc.) are as high as they are.
Agreed. And they also seem to think that teachers are overpaid at $50,000 / yr, but have no problem with traders on Wall street getting million $ bonuses in the year after their company declares bankrupcy. Mystifying.
Maddening in the extreme...
Best explanation may simply be the following, courtesy of George Carlin (heard on the radio tonight):
When you're born you get a ticket to the freak show.
When you're born in America you get a front row seat.
Obviously those traders are our new cultural heros. Teachers and especially other public employees who aren't in the official Pantheon (police, fire, soldiers) are the new heels. If you doubt my first sentence, just watch any business or investment show on the telly. Stock pickers are who we lionize.
I'm not so sure about the "outnumbered 1000 (at least) to 1" presumption.
If I surveyed all the family/friends/neighbours I'm in regular contact with - many of whom I have personally raised to some degree the subject of peak oil - I would say the number is definitely closer to 50 (or less) to 1. Which isn't hopeless.
Then again, your 1 in a 1000(+) is more accurate if we're talking about those trying to kick the BAU habit. Even 100,000(+) to 1 might be quite likely. :-[
How I wish I was a "1".
Cheers.
Me thinks you exaggerate. Its probably more like 10 to 1.
It's not surprising that many North Americans are badly informed. Much of the news coverage has been dreadful.
In today's edition of the Ottawa Citizen, David Warren has a prominent article on the editorial page under the title "Dig, baby, dig". It is breathtaking how complex problems are framed in simplistic terms. A few examples:
"would you rather have your oil at the expense of a few slow-witted dead ducks, or with the blood of a million Arabs?"
"Under Obama, they [the US] now demand it [regime change] for a broad selection of their friends."
"proven reserves of shale oil vastly exceed the reserves of liquid crude ... its amazing what an enormous supply of hydrocarbons was laid in on this planet."
"[on environmental issues] Most of the world now grasps that anthropogenic "global warming" is a sham. Pollution is the real question, and happily the question to which there are more and better technical solutions."
"I cannot help, but think that there are two morals to this story. One is, "Drill, baby drill." And the other is "dig, baby, dig."
"swing consumer"
That's an insightful view of the US position in the global oil market. And our future consumption WILL be lower in any case. So your idea of fixing our transport system is spot on. But most Americans would rather just suddenly run out of gas before they will accept anything that radically changes their lifestyle, IMHO.
Interesting idea but here in the UK, where we like to tax anything and everything to the max, more than half the cost of a gallon of gasoline is tax. Despite that people seem to be driving more than ever.
Currently there's been huge controversy around raising this even further by just a tiny amount - 1p or 2 cents per litre (approx 10 cents a gallon). So any major tax hike would be met with fierce criticism and loss of the next election plus a probable dropping of the tax.
Even if the US did get past those problems surely a swift hike in the cost of gas would have severe economic consequences for the US - perhaps a national recession?
Rationing private car use might be a better solution or for a very quick fix putting the speed limits back down to 55 mph.
Great analysis, as always.
But look for a second at the last sentence: "I am doubtful that the new oil shale sources can ramp up as quickly as hoped, but there is at least some glimmer of hope that these fuels will help keep the day of reckoning away a bit longer."
Glimmer of hope for who? Those who can squeeze an extra few years of easy livin' before the crash? -- a crash that will only be worsened by the delay? Isn't this a rather delusional, psychopathic form of hope? Is this the best we can do -- delusional hope?
I make a plea here for OPENING OUR DAMN EYES. The paradigm shift in fossil energy is upon us. The decisions we need to make are uncomfortable but obvious. MAKE THEM. (www.postpeakliving.com)
I hear what you are saying and don't disagree. But I would appreciate the extra "time" if we can get it. Not for any illusion of "preparing". The more I have thought about that it is a fool's chase. But time to live and play and watch my children grow up, even if we just get a few extra years.
I don't understand people who want this way of live to end sooner than it has to. We all know this is finite. I realize how ugly things will get. But I have found peace from living in the moment.
I get where you're coming from -- I too try to appreciate the good things in my life at present, which are many -- but I find no peace from living off the destruction of the future, which we surely are.
This 'eating of the future' is the terrible, unavoidable truth of our civilization and it gives me only pain -- a pain overlayed with the good, but a horrible, ever-present pain nonetheless.
To not experience such pain along with the joy of life is to be either dangerously ignorant or to be a monster. And to not address it with action is morally criminal.
Here's what I do: http://www.energybulletin.net/stories/2010-12-13/agriculture-stands-chan...
As Catton wisely observed in 1980, the best way to avoid a worst-case crash scenario is to act as if that's the most likely outcome.
"Extra time" is good or not depending on what is done with it. "Extra time" will most likely be spent growing the GPD, the population, and our vehicle fleet, and every oil-dependent bit of infrastructure we can...I hate to sound like a pessimist, but more oil tends to make people think and behave like there's more oil, and the consequences of overshoot are worse the farther out there we get.
degar7 opined:
More time to keep the CO2 PPM climbing in the atmosphere? Good thinking, Degar.
I am afraid we don't have too much to say about the nature of the crash. I am not sure we can even do much about the timing.
But to the extent we can put a crash (of the type foreseen in "Limits to Growth") off, I see that as beneficial. Moving it forward doesn't provide any benefit in my view at all. It doesn't make the crash any less severe, or the world able to sustain any more people after the crash, as far as I can see. If we had taken action in 1972, perhaps some longer term changes could have happened to make the crash less severe, but given where we are now, I don't see any positive benefit at all.
Moving the crash forward does make people feel like they are "doing something." My question would be, "For whom?"
I agree we cannot do much about the timing. BUT...by actively creating shadow structures NOW, to take over essential functions when the crash arrives, we can likely lessen some not-insignificant amount of pain.
But shifting our time/material resources to these 'shadow structures' (i.e. creating local food, energy, transportation, manufacturing systems, etc) requires that we give up trying to pathetically prop up this destructive behemoth of a a civilization for one second longer than it would otherwise last.
Every bit of effort working on the boondoggle of shale oil is effort wasted -- it is effort that COULD'VE been spent on creating these necessary shadow structures. Shale oil/etc is thus a 'part of the problem' -- not part of the solution.
And c'mon Gail -- you do such wonderful energy analyses, but have you no comparably rich knowledge of carrying capacity, overshoot, and other such fundamental ecological concepts?! If you do, I cannot see how you can say, "Moving it up doesn't provide any benefit in my view at all. It doesn't make the crash any better, or the world able to sustain any more people after the crash, as far as I can see." That's a comment unworthy of your intelligence.
To the extent we are building shadow structures, to be helpful for the long term, they need to be built with locally available materials, in a low tech way (depending on biological processes for renewal). This can go on at the same time as whatever else we are doing. It doesn't involve anything that is very costly in today's terms.
You wrote, "[Building shadow structures] can go on at the same time as whatever else we are doing."
No, no, no, no, and no!! You cannot build up local communities, resilience, and biological health with local efforts while at the same time actively undermining those same things with a monstrously destructive, resource-sapping, and childishly-futile efforts to sustain the unsustainable.
You cannot painstakingly build a livable future while at the same time systematically destroying it with 85 million raging barrels a day of industrial energy.
The death-dealing industrial economy and all it's biocidal insanity is NOT compatible with efforts to 'choose life so that we may live.' We CANNOT have both.
+ Good work Dan, you truly get it.
I see a worldwide decline in oil supply as likely leading to collapse, very quickly, because of problems with the financial system. We can't get ready for anything during collapse.
So if we are going to do preparation, it really needs to be while we still have oil supply--at the same time it is in place.
We don't have the luxury of being able to turn off oil, get ready, and then have downslope, in my opinion.
Just so many stone heads Gail.
The heads will be standing but the people left won't have any use for them.
Really the way we are behaving is quite natural and it's called self preservation.....FYJ I'm Okay.
I don't think we'll be thanked for stripping everything. While we "prepare" the biosphere continues to be degraded by relentless population growth. More species will become extinct, the oceans, seas, lakes and rivers mined for food and clean air will be just a memory.
You are right though, we don't have the luxury (any more), it's too late by sixty years. Now all we have left is to make it easy on ourselves. Don't you find that to be sickening?
I'm with Gail on this. We must get ready now while the current system is in place. Once this system falls apart the capacity to prepare will plummet, in my view.
Oh prepare you mean, Disneyland, Las Vegas, Ipads, big screen TV's, McMansions, cruise ships, SUV's........all good preparations. In the meantime to support these energy sapping pursuits, we mine tar sands, drill in deep water, burn billions and billions of tons of coal, explore the Arctic and frac everything in sight.
But who is "preparing"? Is it governments and big business or is it the poor peons so the elite can continue their BAU edicts and also be the ones to get through the bottleneck.
Unfortunatly Bandits is right. No one is going to prepare except a few people in small groups or on the individual level. I'm increasingly comming across people eg tutors and students studying the environment, systems and energy issues, that should understand the problem of resource depletion but dont (although they all seem to think they have climate change in the bag). If these people dont get it then what chance do polititians or the public at large have?
So? Start with where you are with who you've got. What's the alternative? Becoming bitter and resigned? You can choose to do that but I'm not.
Right! I've been aware of oncoming problems for years but still have been making the changes in my life even though I know I'm not having an effect on the big picture. I find that I'm enjoying life a lot more than if I was just going with the flow and doing something that I knew was a major contribution to the mess.
I, myself and me................
Bargaining stage, that psychopathic response hides fear.
You see the enemy. You just don't "know" the enemy. You should though, because it is us.
Read again "The Tragedy Of The Commons".
http://dieoff.org/page95.htm
"I would like to focus your attention not on the subject of the article (national security in a nuclear world) but on the kind of conclusion they reached, namely that there is no technical solution to the problem".
I'm resigned but not bitter. I do try to explain the situation to people close to me but find although they are often nodding their heads yes its not going in. After a two hour chat with my partner explaining the importance of oil in our global economy and its innevitable decline he still later mentioned he thinks its going to be a double dip resession. Must learn some new meothods of re-education.
How are you getting on with the people you know aangel?
Pretty much the same as everyone else...not well. I have accepted that most people will not start changing until the physical world changes around them. Right now the physical world is "locking in" everyone's world view.
So I work with people who get it and are ready to get started.
The key is small amounts of info, over time.
People learn really new things more slowly than we think.
What's wrong with "industrial energy"? The 85 million barrels isn't livable, certainly, but the sun delivers 85 million barrel's worth of energy to the top of the atmosphere in about 3 seconds. We can use it, we just can't expect it from oil.
From the AP article: "And within 10 years, it could help reduce oil imports by more than half..."
Yeah, I could win the big lotto tonight, all of the folks in the ME including Israel and Iran could all get together and sing Kumbaya, folks around the world will decide that a one child policy is their new religion, and the AP could suddenly decide to print only factual information, avoiding couldisms. That would help.
Oil imports will be down by more than half in ten years. The question is whether anything at all will be available to fill the void.
I'm the writer of the AP story referenced above. Great analysis here. A couple of points to clarify: In the story we report that shale/tight/horizontal oil could HELP reduce imports by half. But in order for that to happen US gasoline demand needs to continue to fall, as projected (see related story: http://news.yahoo.com/s/ap/us_guzzling_less_gas and graphic: http://hosted.ap.org/specials/interactives/_business/us-gas-consumption/....) And GOM production needs to get back on the upward trajectory it was on pre-Macondo. As for it being a "new technique" well, that's a question of semantics (and a pretty irrelevant one, I'd argue). Sure, hydraulic fracturing and directional drilling have been tried long before, but the refinements referenced in this analysis that allowed this technique to economically tap tight oil matter and can very credibly called new--not just by me but by the people in the industry I spoke to for the story. Galileo's telescope used lenses. So does the Hubble Telescope. One final thing that I'd love to explore more: While reporting this story one analyst said something along the lines of: 'We've already pulled out 160 billion barrels of oil that happened to have seeped out of the source rock into reservoirs. Now we can go right to the source rock, and there may be another 160 billion barrels there...or some multiple of that.' Wow. Thoughts?
-Jonathan Fahey
If the source rocks had the same recovery factor as the conventional reservoirs, the 160 billion barrel analogy (from numerous US basins) might be approximately correct, but there is a huge difference in permeabilities and recovery factors*. I think that the last upper end estimate by the USGS (which is traditionally wildly optimistic) is for about 4 GB (billion barrels) for recoverable reserves from the US side of the Bakken Play.
*We'll see what the other Oil Patch types say, but in my opinion, whoever made the 160 Gb statement about conventional reservoirs and source beds should be sentenced to 20 years hard labor in Siberia.
On a different topic, you might want to research the difference between Peak Oil and Peak Exports. Some articles to ponder:
http://www.energybulletin.net/stories/2010-10-18/peak-oil-versus-peak-ex...
Peak Oil Versus Peak Exports
Excerpt:
http://www.energybulletin.net/stories/2011-02-21/egypt-classic-case-rapi...
Egypt, a classic case history of a rapid net export decline, and a look at global net epxorts
And my standard comment on the Saudi's "Excess Productive Capacity"
http://www.theoildrum.com/node/7554#comment-770186
Jeffrey Brown
Jonathan,
It is good to hear from you!
After I put this story up on Our Finite World, I got quite a few comments back about how fracking fluids and techniques had been improved and refined, so that more oil can be removed, for the same cost. So I would agree that there really are some new aspects that have come along. I perhaps could have softened that section somewhat. The oil and gas industry continues to improve their techniques, so things do in fact change.
The big question to me, is "How much oil can be extracted at prices that people can afford to pay?" These new (or improved) techniques seem to have as much promise as any. There are a lot of details that have to be worked out too. The new oil needs to get to market some way. Lack of pipelines and refineries nearby tends to keep prices down. But investors don't want to build new infrastructure, if pipelines will only be used for a few years, and if refineries are available, but at a distance.
I have a post up now on Our Finite World, showing some forecasts by Steven Kopitz of Douglas Westwood consulting firm. His firm is optimistic that shale oil and NGLs can play a significant role in the future.
Jonathan -
Regarding the analyst saying that they can go directly to the source rock... there may very well be huge numbers of barrels in this source rock but mother nature cursed us by making that rock SHALE - silt, clay, mud derived - it all can have high porosity and hold LOTS of fluid but the permeability generally stinks other than through intersection of secondary porosity (fractures) and when you're reliant on that it's just a roll of the dice - even if you can get right to the source rock.
I am a hydrogeologist and don't know alot of the details regarding petroleum behavior in bedrock but if my experience with groundwater in shale aquifers is any indication then the amount of water never really is in question when we try to set supply wells in shale... there are HUGE volumes of water in that shale but many of these types of aquifers simply cannot sustain the even larger demand for water that would be placed on them by modern standards... so they may be able to sustain a small development or office park here and there but they are only very rarely (if you happen to hit the right fracture zone) going to be able to be utilized as a municipal supply (unless you drill many wells - with the associated astronomical costs). Hydrofracking is often done in these formations to improve yields and it does, often marginally and often temporarily.
But everyone involved in groundwater resources knows that if you want truly consequential yields from wells you need sand and gravel aquifers, the low hanging fruit of the water world. Those reservoirs the analyst spoke of were like the sand and gravel aquifers - they were exploited first and it is very difficult and costly to try to utilize that higher fruit, regardless of how much of it is hanging at the top of the tree.
I think this description coincides precisely with my analysis right below in the comment thread http://www.theoildrum.com/node/7499#comment-772228
Transport of liquids in porous material and channels should be a pretty much universally understood topic. The liquid either moves around by drift or diffusion. If one considers that disorder in the pathways generates all the dispersion in the flows, one can explain just about any breakthrough curve that a hydrogeologist would measure. This includes oil moving into reservoirs or locked in place, or water moving into lakes. The size distributions follow from exactly the same statistical dynamics.
I discussed this in The Oil ConunDrum because, and I know this will sound pretty hard to believe, but no one else ever considered this idea before.
Johnathan, thanks for popping in. Continuous incremental improvement is widely underappreciated. It just doesn't grab our attention -we've been spoiled by action/adventure entertainment. Improving something by five percent per year and sustaining that rate for decades just doesn't catch our attention. I made a pretty good career, making incremental improvements in computing. And that pretty much how the Japanese auto industry came to dominate ours.
Thoughts?
Your -2mbpd is optimistic. But, I do think we are likely to see .5 to 1mbpd increase, and if we can keep decreasing our net consumption, we might get halfway to your projections. Not enough to keep true happy motoring going, but hopefully enough to stave off disaster.
Yeah, whoever said that was either confused about or unfamiliar with how petroleum is generated. It's source rock. It hasn't been transformed into oil yet. Was this person talking about tapping shale that is in the process of being converted into oil, and catching the oil at the source? That makes sense, perhaps, if it could be done economically. Or catching the oil as it migrates upward.
Or was this person talking about retorting at depths of thousands of feet? Barring some advantage in the free amounts of heat/pressure that won't fly, either.
@KLR, I think there's another way to interpret that statement. Most OOIP gets left behind. I think the average in American wells is >60% left behind. They've already gone back with EOR techniques and recovered some of that, it is all based on the price (value) versus the expense of the EOR method. There's waterflooding, gasflooding, microbial, thermal, chemical and perhaps a few more I forgot or never heard of.
@enemy of state, improve your 5% incremental improvement per year to 7% and the production doubles every 10 years. That ain't so shabby. It is doable, where there's a will there will come a way, or something like that. :)
That would be working in the reservoir rock, not the source, as was implicitly stated. SPE estimates some 60% of
all wells have been fracked: "Hydraulic Fracturing: History of an Enduring Technology" Fracking was first tried in the 1860s, if you count wildcatters dumping nitroglycerin down holes.
I see that SPE doc conflates source and reservoir in one sentence, too, or rather refers to what was originally classed as source now being considered as reservoir. I'm referring to source in a strict sense here, being a solid matter bereft of porosity or permeability that hasn't been treated at all. I brought up the Monterey as an example of a formation that is both source and reservoir, so it isn't unheard of. Would be interested to hear about more examples of these proto-reservoirs.
Smitty – a couple of considerations for you. Most important: pretty much all the EOR methods that you mentioned have been applied to all suitable reservoirs in the U.S. for decades. In many cases for 40+ years. In fact, much of current domestic production is attributable to these methods. Same can be said for all the major fields around the globe. Often folks who postulate how much oil might be gained from EOR appear to think these techniques were developed and then just set them on the shelf because the oil patch had little desire to produce more profits. This logic always puzzles me.
But let’s assume all the EOR methods could be significantly improved tomorrow and we can recover an extra 10% of the residual oil. Again folks pushing the EOR savior appear to have no sense of the time factor involved. It tends to be incredibly slow compared to primary recovery. Unlike westexas, a crazy wildcatter, I’m a career production geologist. I have studied in detail 100’s of fields undergoing some form of EOR. A generalization: it might take X years to recover the first 40% of the oil from a reservoir. The next 10% recovery might take 3X or longer. And that’s aggressively applying the best EOR methods out there. And to recover the 50-70% fraction: maybe 6X to 10X.
There are a series of reservoirs along the Texas coast that have over 2 billion bbls of proven residual oil in them. And everyone is currently undergoing the most appropriate EOR method: water flooding. A rough guess: average recovery per well to date = 200,000 bbls. Current typical production = 200 bbls of FLUID (oil + water) per day. Typical oil cut = 2% max. So yes: recovering 4 bopd from each well. Remember the U.S. is the 3rd largest oil producer on the planet. And our wells average less than 10 bopd. So lets say a new improved EOR method is going to recover an extra 10% (40,000 bo) of the original in place reserves (400,000 bo). So let’s assume we ramp recovery up to a staggering extra 4 bopd per well. Wait for it…wait for it…TA DA!!! It will take just a mere 27 years to get that next 10% out. You may not believe this but most in the oil patch would consider the model I just offered as overly optimistic.
No…there is no giant cache of oil we’ve been hiding just waiting for prices to get high enough to unleash our SSEOR (a Halliburton trademark): the Super Secret Enhanced Oil Recovery.
Smitty – I’m not directing my sarcasm at you. I’m just getting frustrated with all those armchair reservoir engineers out there who really don’t have a handle on the reality of the fluid dynamics involved.
@KLR, some folks might believe the shale is indeed the "source" rock, when you consider the shale (the part with the high organic content) has been "cooking" for millions of years and has managed to produce some free oil that is hiding in the pore spaces. Then as Rockman says, there is the remaining rock matrix, itself relatively impermeable shale that hasn't cooked for whatever reason. High temperatures, high pressures, no where to escape and millions of years, and you end up with long chain hydrocarbons that humans like to play with and crack into shorter chains for fun stuff like gasoline, diesel and naphtha.
@Rockman, spot on! I am an armchair reservoir engineer. Luckily I don't have to make my living from it, but can basically understand what's going on, since as you keep saying, things haven't changed much for 4 decades or so, right in line with when I went to school on this stuff. I barely need to dust off the old textbooks, mostly thanks to your fine posts. The important thing isn't whether there is some magic EOR bullet, but that folks keep trying to find one. The nice thing about stripper wells is if you throw a lasso around enough of them, show steady improvement they start to look like real production, then you turn around and sell the "package" to that guy with the big cowboy hat and no cattle for as much as you can get. ;)
Lots of folks don't understand why the Canadians are mining the oilsands. In fact they don't know (and I'd love to see someone put together a well-researched article on it here) that Canadian law requires 90% or better recovery(ERCB ID2001). If I pointed YOU to an oil property and said state law requires you to recover 90% of the OOIP, you'd pretty much have to dig it up and wash it to get it all too. Kind of tough to do through a little ole straw in the ground eh?
Canadian law requires 90% or better recovery(ERCB ID2001).
ERCB Interim Directive ID 2001-7: OPERATING CRITERIA: RESOURCE RECOVERY REQUIREMENTS FOR OIL SANDS MINE AND PROCESSING PLANT SITES
This applies to oil sands mines, which normally do recover in excess of 90% of the bitumen-in-place. It depends on ore grade, but they expect 90% of the bitumen to be recovered from good ore.
There's a seven-step enforcement ladder that gets progressively tougher. At level 1 the plant foreman gets a warning letter, at level 2 they talk to his supervisors, at level 3 they talk to senior management, at level 4 they hold an inquiry. I think around level 7 those senior managers who have not already fled the country get sent to jail.
I've been keeping an eye on studies done to improve waterflooding (what we may call enhanced waterflooding) and seeing the results of hundreds of reservoir models run to see what happens when waterflood is enhanced (via chemistry). The rub is once a reservoir is waterflooded, the water creates short circuits within the reservoir, and when one adds the chemical juice to the water, the juiced water has a tendency to flow down the short circuits. I've come up with some ways to get around the problem, but they all take a huge amount of money. Also, there are some subtle techniques which can be tried to improve results when mobility ratio is adverse, but it also takes a lot of money.
So unfortunately, while in the lab we can see a pretty good result, the poor sequencing these reservoirs have undergone (meaning the water was already injected and breakthrough already took place) leads to poor results for "tertiary recovery" or what one may call enhanced waterflooding. I think it's possible to make money out of it at $80 a barrel, but it isn't about to do much more than stabilize production or give us a small burp followed by a long period of suffering as we skim oil from a lot of water and fight like crazy to keep expenses down.
What you are describing is flow dispersion. The breakthrough curves are very easy to model and there is nothing you can do about it because the dispersion is all caused by entropy (seeThe Oil ConunDrum, Vol 2). To reduce the entropy takes a massive amount of energy to create order out of a disordered environment.
I contend that the reason we get these highly concentrated forms of crude is that these forms are mobile and they can travel long distances over glacially-slow time periods to collect in random faulted geological formations. This leads to the entirely predictable range in sizes we see in oil reservoirs, from the small to the super-giants. This is described early on in "The Oil ConunDrum".
Not by any coincidence does the distribution of freshwater lake sizes follow the same mechanism. Water, like oil, will collect in natural geological formations, and with exactly the same distribution -- a few great lakes, and lots of smaller ones.
But what happens when the oil, for whatever reason, is not mobile?
Well, it pretty much ends up where it is formed and you get these huge diffuse areas with perhaps lots of oil, but not much by way of concentrated amounts. All the "base of the pyramid" locations such as the tar sands, Bakken, etc likely fit into this category.
When you look at it this way, you think two things. First, we were historically very fortunate that we had porous regions underground and that salt domes and other faults exist in nature. Secondly, we are really starting to scrape the bottom of the barrel when it comes to easy pickings, as we have found most of the concentrated regions (see Dispersive Discovery).
Disturbing is that you really won't find this kind of technical analysis in any textbook. It's still a mystery to me why no one has ever addressed the subject apart from heuristically drawing the pyramid. I think it has a lot to do with the geologists being focused on the individual physical mechanisms without thinking about the broader statistical ideas. And these statistics form the basis and provide the real relevance for a global oil depletion analysis. It is one of the best examples of missing the forest for the trees that one can imagine.
I think that there is good reason to believe that the shape of the World decline curve is not a Hubbert curve.
What is limited is reinvestment dollars that we get directly and indirectly from the net energy available from existing wells. We need reinvestment dollars even to keep infill drilling going in very old fields, and to keep oil/water separators in good repair on stripper wells. Reinvestment dollars are affected too by tax needs of governments, and by ability to borrow to cover capital costs.
As reinvestment dollars get squeezed, I see a slowdown across the board in a wide variety of oil plays. The ones that have the lowest EROI (and thus need the most upfront investment) will get squeezed first. But if there is a major cutback in credit availability, even reinvestment with a higher EROI could be affected.
Yet this directly contradicts what you say in your post "(Hubbert’s Curve is usually applied only to the liquid portion of oil resources.)"
Just so everyone understands this, I can explain what will happen.
1. The world decline curve will no longer get defined as crude oil
2. The crude will likely be extracted at a faster rate to try to maintain a plateau. It will still be valuable so people will always be willing to extract it.
3. Other forms of liquid will be arbitrarily added to the mix, giving the appearance that the crude supply is not depleting.
Underlying all this is the fact we can accurately model all this behavior without resorting to a heuristic such as the Hubbert Logistic curve.
Whether or not I say "Hubbert's Curve is usually applied only to the liquid portion of the oil reserves," just speaks to what others do, not what I would do. For liquid reserves, it is probably not a bad approximation, as long as there is adequate capital for reinvestment, and a number of conditions that have been common historically to continue to hold.
I think ultimately Liebig's Law of the Minimum determines the path of future production. You have to have oil resources present, but you also have to have investment capital, and reasonable political stability, and the availability of international trade, and probably other things I haven't thought of (adequate food supplies for people doing the extraction, for example).
Again, I concur with Gail. All of the items she lists will be severely stressed. In the latest version of my Preparing for a Post Peak Life video I assert that the Hubbert curve is the best case scenario. It is far more likely to look like this:
A credit crunch and related instability to the system means that we don't get all the remaining oil out i.e. much of even the remaining "easier" oil stays underground forever.
At the same time the Export Land Model is working its nefarious and relentless ways. Here is how oil production "looks" to an oil importing country:
A back-of-the-envelope calculation shows that we lose — just to the ELM — huge amounts of oil in the early years while producer country economies are still expanding but top line production is decreasing:
Shown further into the future, it looks something like this:
Distinguishing the ELM is, of course, the product of the good work of Jeffrey (westexas) and Sam Foucher.
I see parallels between predictions in climate science and those of oil depletion.
In climate science you can make a conservative prediction:
Raising CO2 will cause a certain level of temperature increase.
Or you can make a riskier prediction:
Raising CO2 will generate positive feedbacks that will cause temperature to radically increase
In oil depletion you can make a conservative prediction:
Read The Oil ConunDrum for how to methodically model global oil depletion.
Or you can make a riskier prediction:
Oil depletion will cause a huge squeeze whereby various economies will be driven straight into the ground, taking oil production along with it.
I don't do the riskier prediction because I don't know how to do it, just like climate scientists attack the conservative models first because they are less certain of making the leap. Worse yet, none of the oil depletion theorists have the chops to even do the correct conservative analysis because they are still stuck in the Hubbert Linearization world and lack models that go beyond heuristics. Doing a hand-wavy analysis that essentially leapfrogs methodical approaches is also rife for criticism from people that rely on solid evidence and strong math.
Bottom-line, taking a conservative approach remains a perfectly valid option. In other words, what exactly is the explicit math behind the white curve drawn on the chart? Can you make that algorithm publicly available so someone else can generate that same curve? Climate skeptics rip apart anything they see that is not based on open data and open algorithms. That's just the way the arguments and debates are playing out.
If you are talking about the top graph, no, I can't because it was drawn freehand. To create such a model mathematically would be a ton of work with very dubious results. And it would just lead the conversation to people bickering over the assumptions that were made — just as is happening in climate science. If you are talking about the second one, yes, Jeffrey and Sam make their math available.
But you seem to be stuck on this notion that more math is going make one bit of difference. The problem we face has nothing to do with math. It has everything to do with psychological/human factors. Providing more of what you would call evidence makes no difference if the person you are conversing with:
It is very common for the math people such as yourself to think that if there were just better models, everyone would start agreeing. That's pie-in-the-sky thinking. It has never been the case and will never be the case because it doesn't take into account the human factors I list above.
The graphs I make are intended for people who are intellectually open enough even to have the conversation. That, unfortunately, cuts out a whole lot of people. Better models just aren't going to make one whit of difference with that crowd.
Then, for the people open to listening to me make the case, all I need to do is get the concept across. I know this drives you crazy and you may vehemently disagree with it but I don't actually need to forecast specific production levels at certain time to make my points. I don't need to for the same reason the Limits to Growth people didn't put units on their graph:
We are not dealing with a math problem. We have more than enough "evidence" to make the case. It's overwhelmingly humans factors at play now, in my view. Better math will help, oh, maybe 1% — in other words, negligibly.
Here is a radical statement but one I believe is very true: the climate science fights have nothing to do with the science. The conversations about the science are merely proxy battles. The larger war is ideological. Said another way, the anti-climate change people have decided ahead of time that they don't believe it and then marshal whatever science they need so that they can tie everyone up in knots and run out the clock.
They will tell you, "Give us better models and then we'll believe you." That is a lie. But you, not realizing it's a lie, then dutifully work six more months on a masterpiece. When you finish it, angels come down from above and sign hymns in celebration.
However, most of the climate change deniers have absolutely no intention of ever changing their mind so they find fault with one or two elements of your model and the cycle starts anew.
The problem is that you will not necessarily be qualified to participate in those proxy battles. Look at what is going on in the climate science battles. Like it or not but the climate skeptic side do have the people with knowledge of statistics at their disposal and they are willing to battle the other side over minor and major mathematical issues. There are dozens of these sites on the internet, including climateaudit.org and others. From what I read (and I do monitor those sites regularly), you will not stand a chance with hand-wavy arguments if they start to point their sights at you. This might happen if history is any indication. You don't have to actually do the battle because someone else will that can go toe-to-toe with those people. You will be fine in educating others; the analogy is that you are the equivalent of people like Al Gore and Bill McKibben who can spread the word and let others do the details.
The reason I am bringing this up again is that your charts show levels of certainty in how things will play out, and levels of certainty can only be quantified as probabilities. And to do probabilities, you have to do the math, no different than in climate science. That is where the skeptics will point their sights at, I can almost guarantee that will happen (with nearly 100% probability :)
But is sure has been getting warmer lately, hasn't it?
That's ok. I don't need to for my purposes. I work with the people who have an open mind and for whom there is enough evidence already. I would say there is an overwhelming amount of evidence that indicates climate change is occurring and that we are at the peak of oil production in this decade. If someone doesn't get it from what we already know, there is something else that is acting as a barrier, some human factor, not some science factor.
Most people eventually get to "human ingenuity will save the day even if oil declines." In other words, they accept the possibility that oil will decline — they don't accept the impacts I predict because technology will come to the rescue in time. A different sort of education is required at that point that has nothing to do with oil models.
However, feel free to do battle with those folks if that's how you like to spend your time while I work with this other set of other people. There is room to do both.
Agreed. I am also going after people like Secretary Chu and other bigwigs who don't want the potential embarrassment of missing out on perhaps rather obvious analyses. They do have a lot of pride in doing the science correctly and I am hoping that they don't want to be last to the party and made to look ignorant.
Science in general shows a bandwagon effect and we have to learn to exploit this.
This is pure "faith" just like any religious belief system. Within this "faith" there is no real logic or understanding of how the world works. I think Americans are especially resistant to even considering the realities of our path to societal collapse because the alternative is so destructive to our current fossil fuel energy-dependent lifestyles. Children and adults (via "self-improvement courses and seminars) in the U.S. are taught that if we really want to, we can accomplish anything.
The alternative to the "technology and science will solve all of our problems" mentality is for the vast majority of people to admit the limits of humans and our technology-based society, and voluntarily make huge changes in the way we live with a drastic reduction in many things that make up the "American lifestyle." (Although that change is already being forced involuntarily upon many working and middle-class Americans as the numbers of long-term and permanently unemployed persons grows - I wonder how long it will be before that demographic will become so large that it cannot be ignored by mainstream politicians and media.)
Exactly. That's why I say this is no longer a problem to do with math.
True, but we must also accept the inverse of the argument: Belief that technology will NOT "come to the rescue" (whatever that term may mean in this case) is also an article of pure faith, not likely to be provable in any real way. Let us suppose we were standing beside Carl Benz' first little 3 wheeler in 1885, and we heard Benz say something like, gee, won't it be a great world when EVERYONE can drive one of these, and in all weather, and at 60 plus mile per hour? The technology did not even exist to clearly concieve of such a possibility at that time! It would have been only by way of an act of faith that anyone could accept the world their children and grandchildren would take for granted. Despite most people's understanding of technology as science applied, it is equally as much FAITH APPLIED.
RC
Good article and discussion - thanks! One remark re taxation on oil production (in all its aspects), and how it enters into the projections. Taxation should really be considered as another overhead, ie maintenance of social infrastructure, and long term projections should use estimates of real taxation. Similar to the EROEI calculation.
Sure one can goose or deter activity by adjusting momentary taxes, but those are really subsidies or penalties. And sure there are differences among specific project economics. Just wanted to point out that the article's discussion of tax rates, as somehow related to availability, is another transitory.
People sometimes use "tax free day" of calendar in political discussion. If that's roughly mid-year then it would appear that social infrastructure costs (schools, lawfulness, etc) are roughly 50 pct of total cost.
I've been reading TOD a long time. Thanks for all the good info.
we are really starting to scrape the bottom of the barrel when it comes to easy pickings, as we have found most of the concentrated regions (see Dispersive Discovery).
I've seen comments from people who are drilling there who say that they can make money when oil is over $60. That's not $5 Saudi oil, but it's not bad.
If there are huge quantities of $60 oil, that makes an enormous difference to the overall oil picture, right?
It depends a lot on tax rates--how badly off governments are, and where they think they can get funds. It depends on whether there really is enough of this lower priced oil, and whether there really is adequate infrastructure to move it to refineries. A lot of gas gets stranded for lack of infrastructure. I expect even moderately high priced oil will have a hard time getting pipelines built to it if it doesn't look like it is a source that will be around for a long time.
It depends on whether there really is enough of this lower priced oil...even moderately high priced oil will have a hard time getting pipelines built to it if it doesn't look like it is a source that will be around for a long time.
Yes, if there really isn't a lot, it won't make a big difference. OTOH, my question assumed large quantities.
So, again - if there are huge quantities of $60 oil, that makes an enormous difference to the overall oil picture, right?
But as the cheap oil depletes, will the $60 oil make up for it? Will the loss of really cheap crude, which subsidizes the global economy, allow everything to function normally to extract and produce the $60 oil? With net exports trending down and world production on a plateau, throw in non OECD countries ramping up consumption and things look rough. I would suggest that you have plan, or at least come to grips with the fact that BAU MIGHT be ending soon. Lets hope for the best with our eyes wide open.
No, it won't. Apart from that oilprices will be very unstable. Gail explained many times the effect of expensive oil on the economy. Also very clarifying is the book 'the next economy' from Paul Hawken.
That is rough. Let's say the Bakken delivers the wildest dream: 2 mbd. Then what ? The U.S. economy would try to grow like in the past, which would make it more (not less, what a lot of people think) than ever dependent on oilimports. So that cannot happen. You cannot escape the wall with a finite resource in the current situation (production on plateau, etc what Mark mentioned).
Will the loss of really cheap crude, which subsidizes the global economy, allow everything to function normally to extract and produce the $60 oil?
Sure.
First, both the US and other developed countries got that way with "moderately expensive" energy, not cheap energy. Oil and electricity have been cheap in the US in the post-WWII period, but it was rather higher in years before that: oil and electricity cost much more, adjusted for inflation. The US, and other countries, succeeded quite well in growing strongly even when energy was much more expensive, whether it was coal or oil.
Wind power is quite affordable (if perhaps not quite as dirt cheap as US post-WWI oil and electricity prices), scalable, high-E-ROI, etc, etc. So are nuclear, and solar even if they aren't quite as cheap at the moment (coal is also plentiful and cheap, unfortunately), so I see no reason to expect energy to ever be more than "moderately expensive".
Second, fossil fuels aren't nearly as cheap as they seem. Pollution is an unrecognized, external cost. So are the military costs we're seeing currently of roughly $500M per year. Those pollution costs aren't sustainable (especially CO2), but unfortunately the military costs probably are (in fact, many corporate interests are quite comfortable with them...). Moving away from oil and other fossil fuels will actually be much cheaper in the long-run than BAU.
Finally, let's assume that Business As Usual involved spending about 5% of our economic activity (perhaps measured by GDP) acquiring energy. If the cost of acquiring energy doubles, then we have to dedicate another 5% to that activity. GDP might go down by 5% quickly, in case we'd have a deep recession. Or, it might happen over time - if it took 10 years, then we'd see a reduction in economic growth of .5% per year, for 10 years. After that transition was complete, economic growth would continue. So, a reduction in "net energy" has a significant impact, but it's not TEOTWAWKI.
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With net exports trending down and world production on a plateau, throw in non OECD countries ramping up consumption and things look rough.
If US imports fall dramatically, the US will be much less affected by net export problems.
Nick, I wrote it also yesterday: oilprices won't be sustainably above $ 60 the coming years. Many green energy projects will be cancelled (again) during low oilprices because of recessions.
Now it is, apart from some OILEXPORTING countries, about China and India with together more than 2000 million people. With a rapidly growing middle class. If it is not energy that will limit its growth, then it is food and/or water (and more rapidly because of climate change).
We are already far in overshoot because of (or thanks to) fossil fuels, how long you think it is possible to continue growth with wind- and solarenergy ? 20 years, 50 years, 100 years ?
oilprices won't be sustainably above $ 60 the coming years.
That seems mighty unlikely to me.
Many green energy projects will be cancelled (again) during low oilprices because of recessions.
hybrids, PHEVs, EREVs and EVs will continue to expand - they're the main solution to replacing oil.
how long you think it is possible to continue growth with wind- and solarenergy ? 20 years, 50 years, 100 years ?
Energy won't be the limiting factor. Water will be a problem. Climate Change will be the biggest problem. Climate change isn't really a resource limit. We didn't "run out of CO2 absorption", it's more like we vandalized our environment, albeit somewhat accidentally.
How climate change will affect us is a very difficult question, but I'm not sure that "growth vs Limits To Growth" is a very helpful paradigm.
Nick, wait and see what will happen with the economy when oilprices come close to $ 200. IMO we will see $ 30 oil again.
I wrote it several times in the past: ICE cars are still expanding more rapidly. India is constructing many roads for their new ICE cars. Asia airliners are planning to buy many thousands of new airplanes this decade. Economic activity all planned on using oilproducts. With all that, hybrids,etc is almost a drop in the bucket.
Right, but it can cause a resource limit for food and water. In fact, that process is already on its way for a long time.
Nick, wait and see what will happen with the economy when oilprices come close to $ 200. IMO we will see $ 30 oil again.
I don't think oil prices will come close to $200 for any sustained period. There are too many ways to reduce consumption.
I wrote it several times in the past: ICE cars are still expanding more rapidly.
Sure. That will be the case until the alternatives reach a certain tipping point. Remember the power of exponential growth.
Climate change isn't really a resource limit. Right, but it can cause a resource limit for food and water.
No question, it will cause big problems for both. OTOH, this conversation started about overall economic growth.
At the moment, the world consumes about 20% more calories than it needs, causing obesity almost everywhere. Food prices are rising in large part because of greater meat consumption. Eliminating meat consumption would double the calories available world wide. Further, there is a lot of potential for increasing food production.
Water is primarily a problem for agriculture. Well, the first thing to do is reduce the farming we do in deserts, and the crops that use disproportionate amounts of water. And, of course, meat production uses disproportionate amounts of water.
Yes, but they (China, India, other developing countries, Saudi Arabia, Russia) won't reduce it, unless forced by high oilprices. They will go on just like before 2008. Nothing learned. The same news you can hear now again: with these high oilprices the airlines are suffering. Just like it was recorded on tape a few years ago and they are playing it again.
The high oilprices will reduce trust in the economy, drop stockmarkets and cause another recession. Geithner knows that the economy is fragile, but not the reason why. He tries to solve the problem with money. It is not the best, but he has no other options.
Nick, on this moment every growth projection in the transportation sector is still based on use of fossil fuels. Electricity production increase still based mainly on increase of coal and nuclear. No tipping point in sight.
As you mentioned: Aleklett has total liquids down only 11% in 2030. He also published an article about 1,5 year ago that says that there is not enough oil for recovery of the industrialised countries. His conclusion is that economic growth needs rising oilproduction. If the economy stays fragile there never will be a lot of people that buy electric cars. In still strong growing countries like China and India there is exponential growth of cars. ICE cars. To turn that around we are many years down the road, with oilproduction declining and probably the economies of China and India not growing anymore. And then you expect exponential growth of electric cars ? I seriously doubt it.
Food prices are also rising because of less export, for example less grain from Russia. Drought and flooding in other countries. Food prices are rising because of a rapidly growing middle class in China. Food prices are rising because of rising oilprices.
Eliminating meat consumption is something like eliminating ICE cars and replace them. It won't happen, or not quick enough. In Brazil they are cutting the rain forest to produce meat. People who make a living of that say: "give us an alternative and we stop cutting, it's not our fault that people in the West eat meat". As long as people eat meat, and they will continue to do so, there is demand and rainforests keep on disappearing. Heck, even I keep on eating meat. Bad, I know, but it just tastes too damned good.
they (China, India, other developing countries, Saudi Arabia, Russia) won't reduce it, unless forced by high oilprices.
I agree. On the other hand, I think we disagree about the definition of "high". I think anything over $80 per barrel is "high". That's the level at which substitutes begin to be cheaper.
Nick, on this moment every growth projection in the transportation sector is still based on use of fossil fuels. Electricity production increase still based mainly on increase of coal and nuclear. No tipping point in sight.
Hybrids, PHEVs, EREVs and EVs are growing very quickly. Wind and solar are still growing relatively quickly.
Aleklett...also published an article about 1,5 year ago that says that there is not enough oil for recovery of the industrialised countries. His conclusion is that economic growth needs rising oilproduction.
He's an expert on oil production, not economics. There's no question that an oil shock has an economic impact, due to income/wealth transfers, and it's impact on consumer psychology. But, the idea that rising oil prices will cause a depression is unfounded.
If the economy stays fragile there never will be a lot of people that buy electric cars.
The conversion from horses to tractors continued through the Great Depression.
Food prices are also rising because of less export, for example less grain from Russia. Drought and flooding in other countries.
True. That's temporary. Food prices are a classic boom and bust phenomenon.
Food prices are rising because of a rapidly growing middle class in China.
That's what I was talking about.
Food prices are rising because of rising oilprices.
Only a little because of rising costs. A little more because of growing biofuels.
Eliminating meat consumption is something like eliminating ICE cars and replace them. It won't happen, or not quick enough.
My point: we have an enormous reserve before we get to the point where we can't produce enough food to feed everyone.
Remember, you were talking about overall economic growth: how will rising food prices derail economic growth?
I was thinking: more than $ 150 per barrel. I see still way too much ICE cars sold.
Here we disagree about what is quick. 90% ICE cars sold means ICE cars still growing much faster than hybrid/electric.
Agree. The economy can grow with declining oilproduction/oilexports. But I think not many years.
This I find strange. I thought that you consider Climate Change a greater risk than Peakoil. Even I think that there will be more droughts and flooding in the future. And foodstocks are already low.
This is even on MSM nowadays. With higher fuel and food prices people have less to spend on other things, which can prevent economic recovery.
I see still way too much ICE cars sold.
Prices haven't been above $80 very long, and they're not that far above $80 - it takes a while for people to believe high prices are long-term.
OTOH, there's an enormous backlog of demand for Volts and Leafs.
Some things will change more quickly, like truck and ship speeds.
90% ICE cars sold means ICE cars still growing much faster than hybrid/electric.
Percentage growth is what matters, not absolute numbers. Again, that's the power and mystery of exponential growth - it takes you by surprise at the end.
The economy can grow with declining oilproduction/oilexports. But I think not many years.
Not unless we get smart, as we will, and simply replace oil. Electrical generation in the US, for instance, is no longer affected by the oil market.
Even I think that there will be more droughts and flooding in the future. And foodstocks are already low.
Yes, there will be. And yes, it will be a major problem. But, you have to realize that there's a large margin for growth in food production. Per acre yields in the US and Europe are much higher than in the rest of the world. Not to mention all of agricultural production that doesn't produce "primary" food: coca, coffee, grains for meat production, etc. Here's an article I noticed just today that give a flavor of the potential:
"The advent of “geek farming” in the United States has pushed profits up, driven environmental impacts down and otherwise secured America’s unrivalled status as the most abundant source of agricultural innovation in the solar system.
America’s uncanny talent at growing plants was corroborated in the recently released U.S. trade data for 2010. While the overall trade deficit in goods and services for 2010 sunk nearly half a trillion dollars further into the abyss, agricultural exports rose by almost one third over the previous year for a trade surplus of nearly $40 billion. In 2010, U.S. farm exports reached an all-time high of $115.8 billion."
http://blogs.forbes.com/williampentland/2011/02/12/american-agricultures...
With higher fuel and food prices people have less to spend on other things, which can prevent economic recovery.
This varies by location and the sector of the economy you're in. Oil exporters, food exporters and farmers do better, and importers and consumers do less well. It's a mostly zero-sum thing, that doesn't affect overall world economic growth.
Carmakers have started to make very cheap cars for India, China and soon for Europe also. With oilprices around $100 even more people will buy cheap, efficient ICE cars.
At least a few more years. I think more likely: we will see some more cycles of high and low oilprices.
Truck drivers are under enormous time pressure. And in Europe they are many times slow or 'not driving' because of traffic jams. Those jams take down average speed already a lot. Ship speeds will go down considerably when there are fuel shortages or when the price of oil is so high that it results in a recession or worse. I don't believe in the 'concerted efforts' that will make the transition smooth.
From 1% to 2% to 4% to 8% to 16% in the next decade. And there are cheap electric cars, for under 10K. But look at the pictures of those cars at: http://venturebeat.com/2008/01/10/27-electric-cars-companies-ready-to-ta...
Free will to change or because of smart governments ?
Yes, therefore Peakoil is mainly a transportation problem.
OTOH, I read that there are also farmers who have problems because of high diesel/pesticide,etc prices.
I don't know if it's zero sum. Lately a heard several times that these high oilprices can threaten recovery because people have less to spend. And not only food and fuel gets more expensive.
Carmakers have started to make very cheap cars for India, China and soon for Europe also. With oilprices around $100 even more people will buy cheap, efficient ICE cars.
True. OTOH, EVs can be very cheap and efficient. Buyers of cheap cars will be very sensitive to operating costs, and EVs will have an advantage. That's why the Chinese buy 25,000,000 electric vehicles (in the form of e-bikes) per year.
I think more likely: we will see some more cycles of high and low oilprices.
In each cycle business will get more efficient. A cycle like that might actually be better for PO adaptation.
Truck drivers are under enormous time pressure.
But they're under even more cost pressure. They're slowing down already.
Ship speeds will go down considerably when there are fuel shortages or when the price of oil is so high that it results in a recession or worse.
Shipping fleets pay very careful attention to fuel costs - it's larger than labor costs - and they'll optimize operating costs by reducing speed the instant it pays off.
I don't believe in the 'concerted efforts' that will make the transition smooth.
I know.
From 1% to 2% to 4% to 8% to 16% in the next decade.
Not as a percentage of sales, as percentage growth year over year. That's the important metric.
Free will to change or because of smart governments ?
Both. The US recently raised CAFE requirements substantially, for instance, and pushed GM to produce the Volt.
Peakoil is mainly a transportation problem.
Sure. And transportation can eliminate oil just as it was eliminated from lighting in the 1870's, from generation in the 1980's, most home heating over the last 30 years (in the US), etc, etc.
there are also farmers who have problems because of high diesel/pesticide,etc prices.
Of course - there are always farmers in trouble because they can't compete. You have to look at the overall industry.
Lately a heard several times that these high oilprices can threaten recovery because people have less to spend.
Yes, people say that, but they're thinking of oil importing countries, especially the US. We have to think globally.
And not only food and fuel gets more expensive.
Companies are under enormous pressure to contain their costs, and not raise prices.
I think countries like Libia have the same problem or even more because of many young people workless.
Yes, distribution of income matters.
Thanks as always Gail for excellent analysis. The only contribution I can add is that, like with the ongoing shale gas fiasco, I suspect the full costs of this drilling are not being paid by the oil companies, and that their debt is rapidly growing and will soon become unsupportable. Yes, even as prices get as high as they are today and even higher. You can only get so much blood from a stone, as they say.
The connection with debt is a big question in my mind too. There is always a temptation to be optimistic in many aspects of analysis regarding how long wells will be productive, and much high selling prices will be. (Bakken oil is selling at a big discount to WTI, so a huge discount to Brent.) In recent years (with some exceptions), it has been possible to get financing for almost any oil investment. If high prices start causing recessionary problems and debt defaults, this ready source of capital may be gone. Without pretty continuous drilling, supplies can be expected to drop off quickly.
I wonder why this is?
Is it because that no one in the industry wants to do or is willing to do a logically sound probability analysis of depletion?
Of course that is the answer, but the "why" part remains the mystical part.
Perhaps it is because no one wants to work on a problem that will give a dismal result.
Perhaps because they need investors to invest, to make the wells work.
confound me and my fingers always moving too fast!
It would be useful to have an overview of "shales", properly placing the major shale plays in the US, and perhaps elsewhere, in some sort of context of size, existing production, type, and potential.
I more or less get the shale gas and emerging shale oil plays in Bakken, but I have less context for the kerogen deposits, and I think much of the noise in the press conflates production from the "highest on the pyramid" shale production with "lowest on the pyramid" kerogen deposits.
I personally think having a large but expensive, hard-to-get set of deposits is optimal, as will tend to soften the descent while encouraging adoption of alternative sources. Of course, as long as coal is cheap we will likely just jump over to that source first and then come back to shale. I am doubtful that kerogen is accessible, but would much like to hear about viable (more than unityEROEI) options that may work.
It is my understanding that besides the Bakken shale, there are some areas of the US that my have somewhat similar resources, but that are presently off-limits for drilling. I have not researched this though.
There are actually quite a few areas like this. In addition to the Bakken there is the rapidly emerging Niobrara shale in Colorado and Wyoming, the aforementioned Eagleford shale in Texas (BTW I read something recently which sounds like the Eagleford oil window goes all the way over to Louisiana), Chesapeake Energy will soon be announcing what sounds like a really big play in the oil window of the Utica shale in eastern Ohio, there is also the Monterey shale in southern California (personally not holding up much hope on that one because . . . well, it's in California, but you never know). In Louisiana and Mississippi there is the Tuscaloosa Marine shale which one researcher estimated contains 7 billion barrels of recoverable oil, and, really many more. There's a shale in Nevada and Utah which, from what I've read, could very well be the world's Mother of All Black Shales.
If that weren't enough, many of these areas have stacked plays, with multiple producing zones. I'd recommend perusing this recent presentation from the North Dakota Oil and Gas Division. There are some 5 different producing (or potentially producing) zones within the Williston Basin of NW ND.
Then of course there are many elsewhere in the world. I can show you ones being looked at in Canada, France and Australia, for example. I'd be willing to bet there are some really good ones in Russia, too.
All your rapidly rising shale plays are tiny resource pockets frackable only with billions of barrels of water.
Your abundance concept is nothing but an abundance mirage in a desert of entropy.
That's about 1 year of US consumption. At a more reasonable peak production rate of 3% of total, it's about 3% of that or 600,000 bbl/day. The USA is currently importing more than 10 million bbl/day.
None of this will permit a society running around in Hummers; it won't even supply us at our current CAFE of ~22 MPG. Start setting aside money to buy a Volt (for cash, because credit may be scarce).
That's right, these shale plays are very exciting for the junior oil companies and local businesses, but they don't make much difference in the overall US oil supply situation. The Bakken play is very exciting for North Dakota and making the locals very prosperous, but North Dakota has only 0.5% of the US population.
I don't think you really need to buy a Volt, but trading the Ford F-150 in on a Toyota Prius would be a really good idea.
www.fueleconomy.gov
2011 Toyota Prius: City 51 Highway 48 mpg
2011 Ford F150 Pickup 4WD V8: City 12 Highway 16 mpg.
Annual fuel cost @ $4/gal: Prius $1,200, F-150 $4,615
Annual fuel Cost @ $5/gal: Prius $1,500, F-150 $5,769
Annual Fuel Cost @ $9/gal: Prius $2,700, F-150 $10,385
I'm expecting gasoline/diesel shortages so transportation that requires no fuel, even if just for a few miles, will be valuable. It will translate into less waiting in lines for your ration of fuel.
That's why I'm put my name on the waiting list for the Prius plug-in hybrid.
The true dual-fuel vehicle.
At the moment, I'd say the Prius plug-in hybrid is at the low-cost sweet spot - the Volt might get there in 5 years. Of course, if we included large and very real external costs it would be competitive right now...
At these numbers, it starts paying off to sell an old truck, even at sizeable loss (or even walk away from small/medium size loan) and switch to economic car. It's not only gas savings, but also insurance and maintenance. By now Prius is inexpensive enough that the numbers would work out even for a Prius. Also, it is a smaller amount, but maintenance of an F-150 4WD V8 is not that cheap. I did the swap 1 1/2 year ago switching a medium size SUV to Honda Fit (selling the truck with upside down loan) and using gas and maintenance savings to even out monthly payments. Now it's pure savings. Honda Fits is smaller, but not that smaller inside, compared to e.g. Explorer.
BTW 51/48 mpg Prius finally beat a 2000 VW Golf 1.9TDi with a 5 speed in fuel economy. But Prius has low resistance tires and everything geared towards economy, compared to Golf's Teutonic Fahrvergnugen. I am wondering what would happen if you dropped a good small modern diesel into a Prius. 80mpg? What is the fuel economy of a modern European sub-4 meter hatch back with a diesel nowadays? Mercedes did an experiment of that kind it for a 1992 Mercedes 190 with quite impressive result : http://www.caranddriver.com/features/09q4/mercedes_engine_transplant_mod...
I counted 7 different areas in that comment:
Bakken
Niobrara shale in Colorado and Wyoming
Eagleford shale in Texas
Utica shale in eastern Ohio
Monterey shale in southern California
Tuscaloosa Marine shale in Louisiana and Mississippi
shale in Nevada and Utah
(not to mention ones being looked at in Canada, France and Australia, some really good ones in Russia)
So, the question is: could we get 600k/day x 7 = 4.2M/day?
So, the question is: could we get 600k/day x 7 = 4.2M/day?
And the answer is NO, you couldn't get close to that amount. But thank you for asking.
I don't know. Look at Murray's projection of about 15 months ago, in which he badly underestimated the Bakken's potential - he was very surprised by the actual production.
There was a post on TOD maybe 2 1/4 years ago (by Piccolo?) which did exactly the same thing - IIRC, he projected peak production of less than 200k bpd.
So...do you feel lucky?
More seriously - why not?
Gail - to add to the post from a-c below I'm not aware of any of the other commercial shale plays in the country where there are not abundant privately owned mineral leases that are available to drill if you meet the landowner's price. I don't have a source to varify but I would guess that probably more than 80% of all the onshore mineral lease taken in the last 5 years have been taken in these resource plays. My company has specifically avoided these plays. We've been drilling in the conventional trends. And there is zero competition for these leases. Everyone else is throwing $billions at the resource leases. Except the few of us who are strictly conventional players. And we are extremely thankful those $billions aren't in competion for our leaseholds.
In the medium run, I think it very likely that coal will be substituted for oil via coal to liquids , and the costs be damned as far as EROEI is concerned. The costs will only be measured in dollars.
By the time we are in a real bind for coal, if we don't suffocate first, we might actually have pretty decent mass transit in places with sufficiently dense populations to support it, and the rest of us will have learned to live with gussied up electric golf carts that will go fifty miles at the new mandatory thirty five mph speed limit.We might even have enough small scale pv around to charge a large part of them.
There will be SOME CRUDE for the forseeable future- enough to run really important trucks such as the ones used to maintain the electrical grid.Speaking as a technically trained farmer, I can say with reasonable confidence that here in North America, we can grow enough soybeans, canola, etc, to supply our own agricultural fuel needs at the production level, without food prices going clean out of sight.
But barring a miracle, biofuels are not going to replace oil in the general economy- bau is a dead man walking.
These alternative oil supplies will soften the bau crash-no more than that can be expected, but we need not starve or die of thirst or starvation, except thru mismanagement.
My money is on the clowns in charge doing the clown thing and running us full tilt into something really bad, right up to WWIII.
Mac,
We were talking about batteries on another TOD post, and you asked about weight. Could you tell me, in your experience, what is the total weight and ballast requirement for a modern typical tractor?
What would the average hourly fuel consumption be?
How many days could you use it per season, and how many hours per day?
Wikipedia
e.g. a 100 hp tractor (60 kw) running 10 hrs would require 600 kwh. At say 5 kg / kwh, thats 3,000 kg. Our old Fordson Magor on the farm where I grew up had 55 hp and weighed about 3,000 kg, to which we added 500 kg of cast iron weights and 500 kg of salt solution inside the rear tires for added traction. That 100 hp tractor likey requires 8,000 kg total for traction, leaving 5,000 kg for the frame, transmission and drive system. Certainly easily do-able, even if using some high-strength aluminum structures were necessary, though I doubt it. Note my estimate assumes 100% discharge of batteries, never a good idea. Probably smart to provide to swap the battery pack out every 5 or 6 hours.
Energy Density of Diesel Fuel - The Physics Factbook That 55 hp tractor carried a 16 gallon (60 litre) fuel tank. Assuming it got 33% fuel efficiency, it needed 35,000 * 100/33 = 105 kj / second to operate full power. 105 x 3600 = 370,000 Kj / hr. = 370 Mj / hr. = approx 10 litres / hr = 3 gal / hr. So its 60 litre tank could only operate it at full power for about 6 hours. If I recall, that's about correct, since we'd only run it about 75% power and get a good 8 hr shift from a tank, about the same as the example battery above.
Is 33% effic. too high for a diesel farm tractor from the 1960's?
I suspect it is. I forget the conversions, but a US gallon of diesel has about 40kWh of energy. If engine efficiency is 25%, that's 10kWh per gallon. If you got 8 hours from 16 gallons, then that's a 160kWh battery.
It's also fairly likely that the tractor will not travel over a very wide area during that time, so it's not impossible that a charging point couldn't be installed somewhere in the middle of that area. Use two thirds of the battery over 3 hours. Top it up to 75% on a fast charge on something like 200kW over quater of an hour and then use for another 3 hours.
Nick, Great question, I have posted on this in the past. Tractors seem to me to be a logical use for battery propulsion. A 70 KWH lead acid battery, weighing 3000 pounds has a cost of $7000. It would run a small tractor for a significant period of time and the weight is an asset not a detriment. PV solar or hydro, both could recharge the system, either in off times or with a replacement battery.
Electric propulsion has tremendous torque which is the critical factor in a tractor. Not normally a lot of extraneous stuff to run, other than a hydraulic pump.
Yes, lead-acid is a very nice fit here: lower capital cost, greater weight.
For that system, you'd want to have two battery packs.
One to charge during the day while you are running the
other in the tractor. Swap them out in evening after the pack is fully charged from whatever alternate power sources you have if the photovoltaics did not fully charge the pack.
Note: this would also work for other EVs, ie truck stops would become pack exchange stations for long haul trucking, for example.
There is hardly such a thing as a "typical" tractor as the size of them depends on the kind of work they are used for;in orchard work, which is what we do, primarily, a tractor in the range of forty to about eighty horsepower is more than ample;on a big midwestern grain farm, two hundred and fifty horsepower is probably "typical".
A forty horsepower "utility" tractor will plow two acres per hour in good going and run a mower or hay baler or pull a wagon over soft ground loaded with five tons of hay;it will tow a thirty thousand pound truck up a steep hill. It wieghs about 6,500 pounds. Being small, diversified operators we simply don't need anything bigger, as we can't justify the cost.
Our "big" tractor is only forty horsepower, but we use it to tow an air blast sprayer fitted with a hundred and sixty horsepower engine, and we haul our crops out of the field on trucks rather with than wagons, etc.
We have a 15,00o pound "backhoe" that is not much used for farming as such , but gets a lot of use on farm projects;it has a hundred horse power and typically burns fifty gallons in eight hours.
Wieghts usually range from about two tons right on up to ten tons or so , with some being much heavier than that. .A small tractor typically uses two gallons or so per hour. I have operated large tractors that used on steady hard work such as plowing use around ten gallons per hour.
The largest particular models I have personal knowledge and experience of wiegh around ten tons and may have additional ballast added in the form of cast iron wieghts or liquid filled tires and can use up to around ten gallons per hour . These would be considered only midsized tractors out west.
The details of the construction of high horsepower electric motors are beyond me, but I know that they can deliver very high torque-meaning they can produce a lot of horsepower at very low rpm.Tractor drive wheels operate at speeds so slow you can very easily count the revolutions by eye, while putting down the full rated horsepower of the tractor, or close to it.That is an ungodly amount of torque, which explains why farm tractors often have planetary final drives, whereas four hundred horsepower trucks don't.
If electric motors could be built directly into the wheels of a tractor, eliminating most or all of the reduction gearing necessary when using a diesel, the wieght of a lithium ion or other type of battery up to the job might not be too big a problem, as dead wieght is a necessary evil in a tractor.
But so far as I know, such batteries do not exist, except possibly in cost be damned applications such as submarines or as instantaneous backup power supplies at computer farms.
At present they cost so much as to make the use of them for farming utterly out of the question , especially considering at least two would be needed per tractor, one to be on the charger while the other one is in use. Tractors have to run long hours during busy seasons.
My personal opinion is that biofuel will be much the cheaper and more practical option for a very long time, once petro diesel becomes unobtainium.
One interesting option to consider for this application would be a hydraulic hybrid, perhaps combined with a microturbine.
There are a number of companies working on these, including Eaton and a Dutch company, Innas - http://www.innas.com/HyDrid.html
I guess I'm a fan of hydraulic solutions instead of battery ones for two reasons - they are less temperature-sensitive, and it strikes me that they would be easier to repair in a low-tech fashion.
I guess I'm a fan of hydraulic solutions instead of battery ones for two reasons
Well the hydraulic is merely the power transmission system--you still need to power to run the main hydraulic pump. Battery power, ICE power, some kind of power-Len pretty much discounts the microturbine you suggested for heavy duty. So battery is not actually competing with the hyrdraulic system--your seemed to lose sight of that when you added the above line.
Wonder if the Hydrid design is better in heavy duty apps than diesel electric? Fully hydraulic drive might have temperature issues--the Stryker vehicle, which I believe is at least mostly hydraulic drive, really screams when driving around in -20F and beyond. You can almost hear the rig wearing out.
Simple cycle turbine engines have the opposite suite of characteristics required for agricultural applications. Low fuel efficiency, low weight-to-power ratio, high rpm and high cost. Fine for helicopters, not so much for tractors. Almost any other engine type makes more sense.
Thank you for the info!
Now...
How many days would you (or a "typical farm") use your (their) big tractor per year, and how many hours per day?
We used to do 1000 hrs / yr on a (by today's standards) small mixed farm of 800 acres in heavy clay. We used to consider the life of a tractor was 10,000 engine hrs, though that can be extended with more expensive maintenance. The big machinery out in the western opens is often run by independent "custom" service companies with employee operators working shifts 24 hr/day for perhaps 6 to 8 months / yr, e.g. fleets of the largest 400+ hp tractors, harvesters, supply trucks travel north from Texas to Alberta together following the weather changes. The tractors likely do 3000 to 4000 hrs / yr. Life probably in the 3 to 4 year range. I've heard the combine harvesters are purchased new in Texas each year and retired in north Alberta at the end of the same year, not worth moving them back south.
I wonder what their fuel consumption per hour is, how often they refuel, and how much ballast they use?
Like you, Paleocon, I would like to see an overview of fossil-fuel containing shales with emphasis on their past, present and possible future exploitation.
Estonia has been burning pulverized shale for power generation for decades, and a lot of it. I spent nearly an hour searching the web last night trying to find a comparative analysis and/or discussion of the types of shale, including current and past exploitation. I literally could not find a simple, satisfactory overview of oil shale/shale oil. I did, however, find some answers to my basic questions.
First, how is this shale different other shales that most say are not economically viable?" Apparently the hydrocarbon content of Estonian shale is on average 3x that of US kerogen shale, and that probably is what makes it useful as a directly combustible fuel in pulverized form.)
In Estonia it seems that pollution from the combustion of shale is quite significant. Combustion residue as ash is 46% of the original material. The ash is mostly carbonate based and quite alkaline. Other issues - from Wikipedia:
From "Oil Shale, A Scientific-Technical Journal, Published by the Estonian Academy Publishers
http://www.kirj.ee/public/oilshale/Est-OS.htm
My overall impression is that some shales are useful as a directly (although very polluting) fossil fuel, and that most shales, especially in the U.S. need to be refined/converted to liquids, and that has many problems, both in cost issues and environmental problems.
Dave Summers (Heading Out) has written about the various processes of "cooking" the kerogen shale, to form a liquid oil. See for example:
Tech Talk: Using heat to refine kerogen from oil shale
Nuclear weapons and oil shale (Tech Talk)
Tech Talk: Charcoal, Oil Shale, and the Ecoshale Process in Utah
Tech Talk: Producing Oil Shale by Burning it in Place
It sounds to me like what people in Estonia are doing it is mining the oil shale, taking it to the location where it is needed, and burning it, more or less like low-quality coal. I haven't really researched why we aren't doing the same, but my impression is that we have plenty of low quality (or even medium quality coal) that we can use instead. The oil shale is in a pretty remote part of the US, making transportation costs high. I believe most of it is buried, so mining it also requires a certain amount of energy. My guess is that when mining and transportation costs are combined, oil shale is at least as expensive as coal, and has more residue, and more environmental problems, so we use coal instead.
Also, electrical generation stations would need to be modified to use oil shale. Unless there was a regular supply in the future, I doubt this would be done.
Also, electrical generation stations would need to be modified to use oil shale. Unless there was a regular supply in the future, I doubt this would be done.
Well of course electrical generation stations could be built specifically to burn kerogen in the heart of the mining region--lets pray we don't sink to that.
I think it is an optimal setup for a trainwreck. The propagandists confuse the people with the potential size of these reserves, and the people are unlikely to support preparations for ever dearer oil. So we will try to sustain BAU until we hit the wall.
Interesting analysis- I think its really too early to tell what effect the onshore drilling boom will have on US imports and peak oil- In general I would say it may arrest the US production decline but I don't see it growing production.
Curbing gasoline use or, even better, encouraging natural gas replacement either through CNG or electric cars would do far more to address imports than onshore drilling.
One small correction- Eagle Ford is in Texas, not North Dakota. You were right though that almost all the rigs drilling in North Dakota are targeting oil but it is primarily in the Bakken, with some testing the Three Forks formation.
Sorry. I had fixed the Eagle Ford issue a while ago on the OFW version of the post. Didn't realize this version didn't get fixed.
No problem- just additional note- It's the Three Forks-Sanish - (not spanish)
Thanks for this analysis - with the growing attention being paid to this it is very timely to look at the "next big thing" that's going to save us (well not really - let's just kick the can further down the road but why would we start worrying about the future now... that's in the future) with a critical eye.
It's great to see a concise discussion of the major points of consideration when getting past simply the media talking points. Thanks to all the TOD regulars (and irregulars) for the follow-on discussion in the comments as well. Definitely good to have a singular resource to point any "true believers" to so they can see there's a lot more complexity regarding the Bakken et al. than the talking points from chain e-mails might lead them to believe...
I simply astounds me that anyone might believe that an additional 2 mmbpd of domestic production by 2015 might do anything but compensate for depletion in other domestic production fields. Eliminate foreign imports? Who is it that's peddling this crap?
The 'craze' has spread to Europe:
Stepping on the Gas - New Drilling Technologies Shake Up Global Market
A study by Werner Zittel, board member of ASPO Germany, found the potential in Europe for unconventional gas to be limited. The resource base is smaller and environmental regulations are more stringent. Numerically:
(study in German, PDF)
I did an analysis of drilling requitements based on decline rates some years ago, and concluded that production will never be more than modest, Can't find my data now, but did send the following to a couple of excited friends back in Sept 2009:
I followed up on a tout sheet about 18 months ago and dug up all of the detailed factual information I could find on the Bakken. Pay attention, there will be a quiz after the lesson'
First lets deal with some terminology. In the "erl bidness" they speak of "resources" and "reserves". Resources are what might be available some day, at some price, and with some level of technology, using other people's money. Reserves are what is likely in the ground with known technology and at a reasonable price projection. But then there are 3 levels of reserves, - possible, probable and proven. Reserves are estimated after extensive seismic survey and analysis, plus drilling a couple of test wells. Possible is a 10% probability estimate. Probable is a 50% probability estimate, which is the case most likely to be missed or exceeded. Proven is 90% probability after extensive development. In the USA, for investment purposes, the SEC allows discussion of "proven" only. iN THE REST OF THE WORLD "probable" is the number generally used. Anywhere from 10% to 80% of "probable" might be recoverable, with an average around the world of 30-35% realized. When you hear talk of "resources" run for the hills, and zip up your pockets.
Now for the Bakken. The formation is what was the shallows of a once vast inland sea in North America, that was rich enough in marine life to create what became some quite rich oil bearing strata. It is part of the Williston basin and has been known of at least since I was in college in the early '50s. The stratum of interest is at depths of about 4500 to 12000 feet and is only about 10 to 50 feet thick. It only became practical to develop when horizontal drilling and progressive fracturing technologies were developed, eg, in the present decade.
How much is there? Well, in 1995 the EIA estimated 150 Mb recoverable (old technology). Then in 2000 a USGS geologist wrote a report that was not released claiming 270 to 500 billion barrels of resources, of which 10% might be recoverable.. .Then in April 2008 the EIA published a new report claiming reserves of 4.3 billion barrels. It was not clear to me but I would guess that that number is "proven", ie - 90% certain. That's less than 1% of the famous 500 billion barrels.
As for fuelling America for 2041 years (where did that number come from?) we use about 7 billion barrels per year, so even the mythical 500 billion is less than 80 years.
My guess is that "probable" is in the order of 50 billion barrels and possible might be 150 billion - so quite a bit less than Iraq, but still pretty good.
The problem is production rate. The two key factors in oil are "stocks" and "flows", and it doesn't much matter how large the stock is if the flow is miserable. Bakken wells are expensive, have fairly low initial flows and decline rapidly. It takes a lot of wells to do much. It might produce 100 million barrels per year some day, but the USA uses 20 million barrels per day! Big deal.
As for the Rocky Mountain 2 trillion barrels - another partially true myth. First it's "shale oil" which is not oil at all. It's kerogen, which has to have a couple of hydrogen atoms added to become light crude. and then it is tightly locked in the bearing rock, and can only be separated with greta difficulty, and with an energetic yield of from 1:1 to 3:1. Not very attractive. Then there is a matter of grade, maybe 15% of the deposits are rich enough to process. The rich "rock" will burn if thrown in the fire, and the Estonians have used their endowment as a substitute for coal to generate electricity for some decades. the traditional way to produce the kerogen was to cook the shale in a retort, leaving tailings of 3 to 5 times the volume of the original rock (think of popcorn), and requiring a lot of water, which the territory in question doesn't have. Shell has been working on an "in situ" process for some years, and expects to make a decision in 2012, and my bet is that the decision will be "forget it". Even if production ever did start, the "flow" will always be very low.
So you have a big load of mythology based on some completely non-understood kernels of truth. You may want to advise the copy list to not get excited.
Yep - basically the definition of a well set in SHALE.
Cat – Great details from all. But I’m going to drop back to a very basic level. So basic some may take it as patronizing but please don’t.
Oil will not flow out of any shale rock at a rate that has any meaningful value. No shale…the Eagle Ford, the Bakken, etc…no shale. But watch my words closely. I’m saying no oil will flow out of the shale rock matrix. That’s the actual rock itself. The oil being produced is coming out of the natural fractures in the rock. Over millions of years the extremely low permeability shales filled these fractures with oil that was generated within the shales. Thus the source rock contains the reservoir. But the source rock itself is not the reservoir…it is the fractures that are the reservoir.
This explains the production character of these plays: the fractures drain their oil very quickly…much, much faster than would flow thru a conventional reservoir. OTOH once these fractures produce their contents the shale rock itself (the matrix) flows oil back into the fractures so slowly as to be unimportant. Someone might calculate XX billions of bbls of oil in one of these formations. But if they are including oil contained in the matrix then the great majority of that oil will never be produced regardless of the price of oil or any conceivable tech advancement IMHO. The only producible oil is what is contained in the fractures.
Besides occasionally higher oil prices what greatly increased potential recovery is horizontal drilling. Drill a vertical hole and you might just cut one or two natural fractures. The fractures tend to be more vertical. One can frac a vertical well and if lucky hit several more natural fractures. But drill a well horizontally in the same area you could cut a dozen or two fractures. One can improve a horizontal by frac’ing it also: in addition to the fractures it cuts the man-made fractures could reach out to other natural fractures the well didn’t intercept.
And that brings us to where we are today. Not only are the wells being drilled horizontally but now at distances of 5,000’+ compared to 500’ just 20 years ago. And 20 years ago they might pump one frac down that 500’ lateral. But now they’ll pump 12 or more fracs down a 5,000’ lateral (BTW: Maersk is drilling 30,000’ laterals in the Persian Gulf these days).
That’s why the combination of high oil prices and the multiplying effect of very long laterals with multistage fracs has these trends so hot today. But it doesn’t change the reservoir dynamics: the oil is in the fractures…not the rock per se.
IMHO there has been no technology developed to drive these plays. Horizontal drilling and frac’ing are decades old. Constant improvements in the length of laterals and the number and size of the fracs pumped. Perhaps the author talked to the frac and drilling salesmen who wanted to impress. Both techniques have been greatly improved for sure. Buy NEW TECHNOLOGY? Complete BS IMHO. But hey, what do I know: I’ve only been designing hz holes and frac jobs for over 20 years. And 20 years ago everyone knew there was oil in all these different formations. It just took improvements in the technology and higher oil prices to set then on fire.
Is this the same geology as the Canadian Bakken? I never paid much attention to it since all the Canadian interest in air injection was with the tarry stuff, but I had formed the impression that Bakken was conventional rather than shale oil.
hot - I hope some Bakken expert chimes in. But from what I know some of the producing intervals in the Bakken are not pure shales. I think there are some sandier intervals within the Bakken that produce. But I think having fractures is still critical.
So I better stick with what I know. Essentially shale, by definition, is a rock type that can not produce anything: oil, water. mangos, nada. Doesn't matter where in the world it is or what the name is. None of these shales produce oil...it's the fractures in the shale that produce the oil. Doesn't matter how much oil anyone calculates is trapped in the shale...only the oil in the fractures will be produced. And that's not easy to estimate under a square mile with a couple of holes in it until you deplete the wells and back calculate. So how confident should one feel about estimates of recoveries from tens of thousands of sq. miles with few wells drilled. I've drilled hz wells in fractured reservoirs with a whole lot of technogy applied and still couldn't make a reliable esimate of future recover. You drill it, frac it and sit back and wait to see if you did good.
Is the Bakken a "conventional" reservoir? Guess how one defines it. The Canadian tar sands are unconventioal IMHO. It has to be minded for goodness sake. But having dealt with fractured shale reservoirs for over 30 years it difficult for me not to consider them conventional.
Rockman -
Thanks for your excellent explanations regarding shale and all other things oily :)
As I mentioned upthread I'm a hydrogeologist typically dealing with wells of much, much shallower depths than you do. I think you had mentioned that these horizontal wells are often drilled at depths of thousands of feet. How are there open fractures in the formation at this depth - I was under the impression that at those depths there is little open fracturing present due to the lithostatic load from the overlying strata. If the fractures are remnant and "reopened" thru fracking it wouldn't seem like there would be sufficient time to allow oil to migrate into the newly opened fracture zones.
Thanks again for the info.
Catskill
Cat – That’s a very good point that isn’t often explained. Rock that has been fractured naturally can lose much of its fracture system by either compression as the rocks are buried deeper and also by the precipitation of minerals in the fractures. Many minerals become unstable under the high pressures and temperatures developed at depth and will readily disolve and migrate into fracture systems and be redeposited.
But to your main point: we can pop a fracture wide open when we pump into it but as soon as we turn the pump pressure off the fractures close back up. Fracturing the rock is simple. The real science in frac’ing is injecting “propants” into the fracture when it’s opened up. That’s the tough part of the job. Some methods work better on some formations than others. The composition and grain size of the propant is critical. Carefully selected sand grains are a common propant, When the closure pressures are very high the sand grains can be crushed and we’ll use very strong ceramic grains for the propant.
FOR ALL: while we're digging into the details I'll offer a little more insight into how we gologists like to mess with your minds. Not are "shale" reservoirs are shale. The Hayneville Shale became well known when the shale gas play heated up. Where I was drilling the HS only about 1/3 of its thickness was shale. The majority was actually carbonate...more commonly known as limestone. The Austin Chalk westexas referred to early is a rock often made of carbonate grains the size of the shale grains we've been talking about. The 30,000'+ horizontal laterals I mentioned being drilled in the Persion Gulf are a similar "chalk" that produces NG. The main reason the laterals are so long is that the field is offshore and thus the wells have to be driled from platforms.
Thanks for the reply Rockman - I think I need a bit of clarification on one aspect of the shale fractures and frac'ing... sort of a chicken/egg questions that I'm not clear on...
So if you are having to frac the shale at depth and prop open the fractures, what is the ultimate source of the oil that you are recovering - not other fractures at that same depth, right ? Because there aren't really open fractures at that depth due the compression / mineralization mentioned above and it seems like it certainly wouldn't be migrating out of the matrix since that would be a very slow process... so am I correct in assuming you are frac'ing to intersect other, shallower, fractures that are still open and actually contain oil and that the frac'ing is done to improve the connection with these oil filled fractures ? In general I guess I just don't understand how the fractures you create thru frac'ing contain any oil since they hadn't been open for the long period of time I would think would be required to allow oil to seep out of the matrix of the rock and fill the fractures...
Catskill
Cat – Let me offer a couple of definitions first. The shale “matrix" is the solid rock itself. The factures are, as you visualize, those areas were the matrix is broken. The only oil that will flow at a commercial rate is in the fractures…nothing from the matrix. There maybe be some sandier more permeable intervals in the shale that could add a little oil flow but again this is not the shale matrix. So matters not what the depth may be: the man-made fractures have to intersect “open” oil filled fractures for the effort to be successful. There can still be open fractures at greater depths but you can imagine the number and extents become more limited as you get deeper. This is also why plays where the fractures tend to run more vertical are prefered: the burial forces are obviously vectored primarily in the vertical also. The much lower lateral force doesn’t close the fractures as readily.
Thanks for the lucid explanation--I'm pretty sure a few of HOs tech talks covered this same ground in more detail back when he was explaining fracking and propants but your quick reply saved me an arduous search. Cat had me scratching my head a bit <?- )
That is easy to determine. Did the oil migrate to it's current location? If it didn't then it is not a conventional reservoir, or you can say that it is a conventional reservoir that accumulated glacially slowly into small pockets.
The reason many have trouble seeing this is because no one in the industry even bothered to do any kind of categorization, and further couldn't be bothered to develop simple models of aggregation. The only categorization needed was of the monetary kind.
Web - True...we do tend to be loose with our terminology. For most in the oil patch "conventional" tends to refer how the reservoir is drilled and produced and not the origin of the oil. In the beginning horizontal drilling was looked at as unconventional by many. Now it's as normal as a vertical hole. In fact, inside the oil patch today such terms are seldom used. Everyone understands the nature off the different plays and leave classifications up to others
Did the oil migrate to it's current location? If it didn't then it is not a conventional reservoir, or you can say that it is a conventional reservoir that accumulated glacially slowly into small pockets.
No, that definition doesn't work for me. The oil found in the oil sands in both Canada and Venezuela has migrated hundreds of miles to its current location.
The industry definition of non-conventional oil really relates to production techniques. Non-conventional oil is oil that cannot be produced using conventional techniques.
It's something of a moving target because the industry moves on. The non-conventional oil of one generation of oilmen is the conventional oil of the next. They have to find something new to do to produce their "non-conventional" oil.
The oil in the Bakken Formation is only marginally non-conventional because pretty much everybody uses horizontal wells and fracing to produce oil these days. You really need a good excuse before you can justify NOT drilling a horizontal well and NOT fracing it at these oil prices.
No, that definition doesn't work for me
well maybe we can lawyer it up some and say the oil sands are just overly mature conventional reservoirs of oil that migrated to a huge pockets when the oil was younger <?- )
On a more serious note, how big an effort is the Canadian side of the Bakken getting these days? Would the oil sand operation like to have more of it come on line to help dilute its product?
how big an effort is the Canadian side of the Bakken getting these days? Would the oil sand operation like to have more of it come on line to help dilute its product?
The Bakken is a pretty nice conventional play by Saskatchewan standards which is exciting for junior oil companies. However, even in Saskatchewan, the Lloydminster heavy oil trend is bigger, and on the Alberta side of the 110th meridian, the oil sands are much, much, much bigger.
They wouldn't bother using the oil for diluent for oil sands bitumen. They would use condensate or syncrude.
Of course everything has moved hundreds of miles due to plate tectonics.
However, in terms of relative amounts asphalt doesn't migrate much; I haven't seen parking lots moving around last time I looked.
For this exercise, I don't care about categorization of production, I care about statistical models of how the oil moved around and aggregated due to fundamental entropy considerations. For that I assert that we need to categorize according to physical processes. So according to this reasoning, I put crude oil in a different bucket than coal, and bitumen in a different bucket than bituminous coal.
Of course everything has moved hundreds of miles due to plate tectonics.
However, in terms of relative amounts asphalt doesn't migrate much; I haven't seen parking lots moving around last time I looked.
You don't understand how the oil sands originated. Plate tectonics were involved, but it was the rise of the Rocky Mountains that created the oil sands.
The Rockies overthrust the Alberta plains and depressed the underlying formations by as much as five miles. That created a giant pressure cooker that converted the kerogen in the oil shales underlying all of Alberta (similar to the much vaunted oil shales of the US) to crude oil.
They also tilted the whole province southwest to northeast. All the oil recently cooked out of the oil shales migrated updip from the southwest to the northeast corner, where there just happened to be large amounts of Cretaceous sands to absorb them.
When it originally arrived in the oil sands, the oil was light crude oil, but due to the absence of a cap rock over the sands, the lighter fractions have since escaped or been biodegraded, and what is left is very, very heavy.
That is the simplified version of what happened. There are eight or ten different theories of exactly how the oil sands originated. Given the sheer volume of oil there, some experts believe that at least four of those theories must be correct.
So plate tectonics were likely involved, as I stated.
Here is an interesting calculation that truly explains the scope of the oil sands in a place like the Athabaska region. The claim is that Athabaska occupies about 140,000 square kilometers and it contains 1.7 trillion barrels of bitumen in-place. If I assume that the bitumen is uniformly dispersed across the region, this gives an average thickness of about 1.9 meters deep. I see that the equivalent oil that can be extracted from this is at best 10% to 20% so that the equivalent thickness is perhaps a foot of oil deep.
To me this sounds like an almost completely dispersed volume.
My model of dispersed aggregation of oil within reservoirs or fields worldwide generates a probability distribution of P(S) = 1/(1+C/S) where S is the size of the accumulation and C is a median size. You can argue this model if you want; I have it all written up in The Oil ConunDrum, where I have evaluated several case studies to show how well it works to predict sizes. It could predict oil-in place or scaled recoverable, I only choose recoverable because that is where the data is. It is a very simple formula based on entropy that is easy to work with, much better than that log-normal crap that doesn't make any sense.
The check I want to do is to determine if such a large reservoir as Athabasca can occur statistically as a fat-tail effect from the model. This is all Black Swan type of analysis, if you want to understand in general how it works, read Taleb's book.
If I assume a value of C of 1 million barrels which fits the USA fairly well, and then say that 100,000 fields have been evaluated world-wide, then I can invert P(S) and make a prediction of how often a sample exceeding a certain size would occur. For C=1, then on average 1 out of 100,000 would exceed 1 million barrels*100,000 = 0.1 trillion barrels. This is only on average, it could be larger or smaller. If C=6 million as a median, then one on average would be greater than 0.6 trillion. If we evaluated a million fields, then one on average may be greater than 6 trillion. You can see how this works. If you read the book you will see it is coincidentally very similar to the Odds function used in sports gambling. Just about any common guy off the street knows how to do odds functions, so there is no excuse in not being able to deal with the math behind this.
So that essentially gives the statistical occurrence of super-giants. It is just a matter of whether we want to classify Athabasca as belonging to the category of fields that accumulates according to the probability model of dispersive aggregation. If it actually does belong, it may indeed be the Gray Swan that fits at the top of the pyramid. Same goes for Orinoco.
If on the other hand it is just a large dispersed field that essentially collected the algae in place and moved it around according to geology and tectonics, that also makes some sense. Remember that this stuff isn't that concentrated according to the calculation I made at the top.
The point is that these super-giants rarely occur, whatever the mechanism, whereas the last count of conventional reservoirs is likely nearing 100,000, implying very good statistics for the bulk of the conventional count.
This is an example from the book where I use C=15 and 25 for fields excluding USA and Canada
I am hamstrung because I don't have a complete data set and I can't afford to buy the data, doing the best I can from charts I can collect. It would be neat for someone to get me the complete data set of oil field sizes world-wide and I can tell you what the probabilities are from the model.
And you can tell me I am full of it just like you can tell Taleb :)
. The claim is that Athabaska occupies about 140,000 square kilometers and it contains 1.7 trillion barrels of bitumen in-place. If I assume that the bitumen is uniformly dispersed across the region, this gives an average thickness of about 1.9 meters deep. I see that the equivalent oil that can be extracted from this is at best 10% to 20% so that the equivalent thickness is perhaps a foot of oil deep.
That's more or less true, except that the formation is not that uniform. About 10% of it is mineable because the formation is shallow and thick. In these they will recover about 90% of the OOIP. The rest is variable, and they will use in-situ methods to recover the oil.
The Alberta government estimated about 20% recovery from about half of this area, giving about 170 billion barrels recoverable. This is extremely conservative because any competent oil company could recover twice that much oil. It's just basically drawing a line in the sand and saying, "We have THIS much oil." Everybody knows the estimate is low and nobody cares because it is more than big enough.
Now, there are a lot of other oil sands deposits around the world, including in the US, but they are nowhere near the size, quality, or producibility of the Athabasca and Orinoco oil sands. So they don't really matter in the overall oil picture.
The check I want to do is to determine if such a large reservoir as Athabasca can occur statistically as a fat-tail effect from the model.
Well, statistically speaking, there are two such very large oil sands formations, the Athabasca oil sands in Canada and the Orinoco oil sands in Venezuela. They were both formed by the same method - a mountain range rising and depressing the edge of a sedimentary basin containing large amounts of source rock. In both cases the oil migrated hundreds of miles to its current location.
Canada also has the smaller Peace River and Cold Lake oil sands, plus a variety of even smaller ones, but these are all part of the same trend that created the Athabasca. And it has an oil sands deposit on Melville Island in the Arctic Islands, but nobody expects that to be exploited in our lifetimes. And then there's the Carbonate Trend, which is probably bigger than the oil sands. But this is probably messing up your model petty badly already.
It only messes up my model if I am counting oranges, and then someone tells me that I should start including apples. I just tell them that, no I will not include apples.
In other words, I am not counting all the other variously-sized bitumen deposits which can be buried well below the surface -- and I think the statistics are very slim for being able to verify a similar model for bitumen. For conventional oil, we have between 10,000 and 100,000 fields to map so the statistics for analysis is very good. As you indicate, I doubt there are similarly comprehensive statistics for bitumen. So I say put these in different categories and deal with them independently.
This discussion is valuable because it is a reprise of ones that I have had with cornucopians on this site and others. They too thought that it messed up my model.
Putting bitumen into a different category than conventional oil fields is probably a good idea because bitumen fields tend to follow different rules than conventional oil. In particular, they are much more difficult to develop, so you can't just treat them like conventional oil and assume they will be developed as fast.
But this is probably messing up your model petty badly already
Well WHT might just have to expand it a little--he needs to know how much biomass there was in set times and what the odds where of it getting confined to a spot where it could start to get cooked. Its still the same thing as he is doing, his model should give you a likely distribution of potential accumulation regions and their likely distribution of sizes. Now if he used plate tectonics modeling to find the more probable accummulation regions and worked some timelines in...oops is that what the oil companies do before they start a new exploration cycle isn't it <?- )
I can see your point though. WHT needs to draw a line somewhere for just what he is trying to model.
I don't have in mind that I need to do anything like that.
The misconception that I always have to clear up is that statistics on this scale does not have to have any knowledge on the individual mechanisms except in rather broad terms.
I realize that many people will have issues with this approach so I always have to lean on specific discoiplines that absolutely rely on it. For example, these kinds of probability and statistics models enabled the electronics revolution. Dopants of non-specific nature are added to semiconductors of arbitrary quality and you can figure out current flows and carrier concentrations. The details don't matter too much, as long as you can get an idea of certain mean values, one can characterize the rest.
So the problem I am trying to solve is something like this: given that 50% of all conventional oil reservoirs have less than 1 million barrels of recoverable oil, what percentage of these reservoirs have more than 100 million barrels of oil?
An alternative problem is to state this same question for a bitumen bed. I don't have statistics for a 50% point so I can't answer that question with my model. It's no more complicated than that.
Nothing is really messing up my model, I just don't have any data to test it against.
So plate tectonics were likely involved, as I stated
Well yeah it's in the earth's crust. Plate tectonics are involved in every oil accumulation I'm aware of. The rock strata are tipped and the oil flows...and when it gets trapped by a another tipped strata...well, well
Rocky state:They also tilted the whole province southwest to northeast. All the oil recently cooked out of the oil shales migrated updip from the southwest to the northeast corner, where there just happened to be large amounts of Cretaceous sands to absorb them.
Now that process sounds very much like your definition
Did the oil migrate to it's current location? If it didn't then it is not a conventional reservoir, or you can say that it is a conventional reservoir that accumulated glacially slowly into small pockets.
except that it needed a slight modification of
or huge pockets<?- )
Hubbble Telescope:
Most of the time the oil migrates for tens of miles, not hundreds of miles. When it migrates, it's light, or the viscosity is low becuase it's migrating through a high temperature layer and has a lot of natural gas in solution.
The heavy oil traps were filled with "lighter oil", and then lost the lighter ends via two main processes: 1) the light hydrocarbons evaporated and/or 2) the light hydrocarbons were biodegraded. Most of the time both processes take place. And this is the reason why so many heavy oils are saturated and full of CO2 and methane, this is what the bacteria put out as they eat the light fractions.
I've seen heavy oil fields buried deep, where the light ends ought to be trapped, but they were plumbed to fairly fresh aquifers, and the oil was biodegraded even as far down as 10,000 feet. Sometimes the oil is 8-9 degrees API, mening it's heavier than water, but the oil has enough gas and it swells enough to barely stay afloat. And I've seen fields where the oil has lost its ability to float, and we see the oil drops falling through the acquifer on their way back down again.
I look at the statistics of reservoir and field sizes. I realize that oil collects as a result of migration, in likely a similar statistical manner to how water collects in freshwater-lakes. The exact mechanism does not matter much, all that matters is that it migrates at different rates (i.e. dispersion) and that the collection times and collection areas are also dispersed. If these all follow the principle of maximum entropy where we know that there is some mean value that makes physical sense, then we will see the distribution of field sizes that occurs in nature (just like we see the distribution of lake sizes).
Here is a distribution of Quebec lakes that follows the entropy model exactly
These are universal rules of nature governed by entropy.
So the only question I have is whether we have a distribution of very heavy oil fields that mirrors that of conventional. The analogy would be that of freshwater lakes to saltwater lakes. We know that the number of freshwater lakes greatly exceeds the number of saltwater lakes. The saltwater lakes occur by a much less common mechanism of accumulating concentration over the years, much like heavy oil requires a certain set of conditions.
Somebody should be able to answer the question of whether we have thousands of these bitumen regions scattered around the globe. Are these actually that common but are simply ignored because they have no economic benefit? Or is the fact that only the large ones are identified such as Athabasca and Orinoco, because the economies of scale can be applied? Or is it more like the case of salt-water lakes, which occur rarely because they require special circumstances to develop? These top the scale in sizes because small ones disappear through a process akin to eutrophication or evaporaton, much like tar, heavy oil, etc will eventually biodegrade and thus fade into the background.
I know it is hard to break away from the specific circumstances and think in terms of large statistical processes but that is the way that nature operates and what I think is the correct approach to understand how much is actually available. The Oil ConunDrum
Somebody should be able to answer the question of whether we have thousands of these bitumen regions scattered around the globe. Are these actually that common but are simply ignored because they have no economic benefit?
We do in fact have thousands of bitumen deposits scattered about the globe, but they are too small and have too many technical problems to be commercially producible. The Middle Eastern countries have a lot of them, but they are unlikely to bother with them until their massive conventional oil fields are exhausted. They're having a big enough problem producing the conventional oil.
I think the Canadian portion of the Bakken Formation is basically the same as the US portion. Saskatchewan has about 25% of the Bakken, and there is a little bit in Manitoba. It produces sweet, light oil and there is a bit of a drilling frenzy going on in it.
Rockman, do you have any estimate of what % of the total volume might be matrix and what % fractures? Murray
Murry - No but that's not how we measure the system. It’s the fracture density that’s critical. IOW how many fractures a well might hit. And then there’s the question of fracture extent. A fracture might run a few hundred feet or several thousand feet. Hence a huge potential difference in the volume of oil each fracture holds. And then not all fractures have the same volume per foot of length. Some are more permeable than others also.
When you put all these variables together it very difficult (really impossible) to predict how one of these wells will produce even after it’s drilled let alone before. When we drill a conventional well we'll run instruments down the hole to tell determine if there’s enough producible hydrocarbons to justify completing it or plugging it. In the case of almost all fractured reservoirs plays you can’t do this. Once you decide to drill the well your committing to completing it. And in most cases the completion phase can cost more than the drilling phase. The first hint as to whether you made the right choice is the initial flow rate. But in the end you typically need at least 6 months of production history to know if you have a money maker or loser.
I would argue that the microseismic (both the application and visualization) has only been around since the late 90's in the oil patch... As you state, the fractures are the reservoir - the best way to define the extents of the reservoir in these shales is via microseismic where you can "see" the extent of the fracturing while pumping the frac(s). This allows for better geomodel construction of the "reservoir" which leads to better simulation and prediction as well as understanding the efficiency of the frac job(s). Not really a factor in actually driving these plays but it does help in prediction...
FWIW, what are the properties of the shale (between fractures)? What's the porosity? What does it do if you e.g. heat it?
Good Summary Murray
I had to write this same type of explanation to some of my relatives just a week ago when they got one of those circulating e-mails about the Bakken and Green River formations. Wish I had your piece in front of me when I did it - would have saved me some time.
One correction - I think the April 2008 study that reported the proven reserves of the Bakken was from the USGS, not the EIA.
Here is that report:
http://www.usgs.gov/newsroom/article.asp?ID=1911
I'm with you most of the way but you say
It might produce 100 million barrels per year some day,
and Gayle posted
Bakken oil production (in ND +MT) is shown near the bottom of Figure 4. It appears as a thin blue line that was a bit thicker back in the late 1980s, became thinner for many years, and now is a bit thicker (reaching an average of about 370,000 barrels a day in 2010).
By my calculation that comes to 135 million barrels in 2010 so it looks like someday is now.
But hey now if they can just ramp that up about by about a factor of five--Bakken will be producing what the North Slope was producing twenty years ago. Wonder if TAPS will still be shipping oil by the time the Bakken manages quintuple its current production, if that day ever comes?
Luke, absolutely right. I wrote that back in 2009, and did not update my text. I have been quite surprised that production got that high that quickly.
I think you meant down-hole motors instead of downhill motors.....
You are right, of course. It went through spell check.
Spell-check, auto-complete, and auto-correct the some of the most frustrating conveniences ever known.
You need a better witch.
NAOM
You owe me a new screen and keyboard.
What's interesting is that since 2000, worldwide NGL have increased greatly mostly in Russia and MENA where previously there was less of an effort to recover them.
For example Russia's and Iran's NGL doubled since 2000 while KSA went up by 50%.
Their recovery of NGLs is now up to Western standards so this infusion of 'liquids' into world production is over.
This is what was partly behind the rise in world oil production over the last decade.
http://www.eia.doe.gov/cfapps/ipdbproject/iedindex3.cfm?tid=5&pid=58&aid...
Yes indeed, fortunately the EIA does a reasonable job in breaking these numbers out.
While it seems highly improbable that the Bakken field and other unconventional oil fields in the U.S. can provide an incremental 2 million bpd in production while also offsetting declines in production from conventional oilfields, I would not underestimate the significance of these fields. Here’s a good overview of the history of, and recent recoverable reserves projections for the Bakken from a presentation by Continental Resources – which has more experience drilling wells in that field than anyone on the planet. In terms of recoverable reserves, it is already starting to make Prudhoe Bay and Tupi look small in comparison. Admittedly, flow rates will be much smaller per well.
Continental Resources presentation
If there is money to be made in these deposits - and at current prices, there is - infrastructure will be built for it. You can see it happening right now in the Bakken.
In Brigham Exploration's latest presentation (PDF), on pg. 60 they've got a graphic showing under construction and near-term planned takeaway capacity in the Williston Basin.
Yes, that's correct: Somewhere around 2014 they'll have over 1 million barrels/day in takeaway capacity. And that's ramped up from only about 200K bpd in 2007.
If it can happen in the Bakken, it can happen elsewhere.
BTW Gail your pyramid graphic is rather propagandic. There is no such thing as "uneconomic" oil - some oils are just economic only at certain prices. The line between your "economic" and "un-economic" parts shifts up and down with price. The higher the price, the more oil becomes economic. I thought this was Economics 101.
BTW, in that presentation they've got some really nice graphics on decline rates and EUR's of wells in various spots in the Bakken. If you're interested in that sort of thing I'd highly recommend reading it over.
Why are all those profiles flat-topped out to 2025?
Do those prospectors that do the analysis have any concept of depletion models?
That is a rhetorical question -- of course they don't!
Ummmmm . . . maybe you didn't actually read the graphic, but this is takeaway capacity. Pipelines and rail terminals. Pipelines and rail terminals don't "deplete."
No, I don't think they understand depletion dynamics at all. Just because you put in a flat maximum capacity doesn't make it so. Hesitant to put in a real prediction?
Dude, tell me the last time a pipeline or a railroad terminal "depleted."
Do you know what a "pipeline" and a "railroad terminal" even is? It appears not, since you believe they "deplete." You also don't appear to know what the word "capacity" means.
If you read the passage of Gail's I was responding to, it was all about infrastructure. So I posted a chart showing u/c and planned capacity (infrastructure). It has nothing to do with "depletion." It is pipelines and rail terminals that will be there regardless of how much oil passes through them.
tell me the last time a pipeline or a railroad terminal "depleted
they do wear out and break but not in that time frame
It will be very interesting to see how long the areas served will keep the flow up after they get to 1 million barrels a day. Just how homogenous is the producing structure--generally the easiest to produce comes on line first. Is that huge Bakken area all supposed to be equally productive? Maybe that is the beauty of tight shale formation or more likely its the bill of goods being sold the investors.
Page 19 of the presentation you linked is instructive--look at how steep the decline angle is at the top of the graph--a cumulative effect of the entire stack. Brute force approach is right, its taking lots of new holes to keep those barrel numbers rising.
That's what I was getting at. As Luke H says, look how the striations get steeper near the top.
If these are actually represented of declines of individual areas, you can tell they have significant decline rates of perhaps 50% per year.
So yes, Gale did bring up a strawman of the lack of infrastructure. I usually ignore that because if money can be made then the infrastructure will get built.
Thanks for putting that up WHT. You can see that some of the color bands remain wide as the fall down hill, which I believe (please correct me if I am mistaken) indicates how fast the cumulative decline in the region below color band is.
Question--how do you pull a chart like that off a pdf. file to post it?
In some ways the steepness is only more apparent at the top because the scale is blown up. I think it actually happens throughout the profile, you just don't see it as readily near the base. The bands thinning are indicative of depletion yes.
This curve is very reminiscent of NG fields where they just march down the line with each field having a short lifespan.
which is a sequence of fields with 2 year time constant damped exponential depletion profiles:
Screen capture + Gimp is the easiest way to grab a PDF figure.
In some ways the steepness is only more apparent at the top because the scale is blown up.
The scale is constant bottom to top on the Williston graph, it is just that as more and more declining curves are stacked on top of each other the overall downward slope gets steeper and easier to see at the top. Lots of new holes have to keep being added to keep the peak climbing.
Now if some high enough minimal flow runs out many, many years enough holes should be able to keep a million barrel a day pipe full even after they run out of places to drill productive holes. 48000 holes is a lot of holes. The pipeline/rail transport infrastrure would seem to have to be planned to give maximum area minimum distance to good transport.
It will be interesting to see how long then can milk those holes. It would seem lots and lots of real small fractures containing very little oil might have a heck of a cummulative downslope once they run out of new hole prospects.
I'll have to expand my horizons and learn about screen capture and GIMP, thanks.
Hubble Telescope:
Earlier, I used the total estimated resource base to guesstimate the area would top out at about 1 million BPD in 2020. I realize some companies estimate this will be reached a lot sooner, but after I posted my estimate I noticed others posted information which confirmed the 1 mmbpd figure was a good ballpark estimate.
Regarding the timing, I think the projections shown are optimistic - they are meant to hype oil stocks, so buyer beware. This usually ends up being a cart and horse issue, companies don't drill wells they can't produce, so they wait for the line to be ready before they drill to line capacity, and the pipeliners don't like to lay line until they see commitments. It takes time for people to sort out their conflicting aims. On the other hand, being able to peddle the stock may indeed cause a stampede, after all this business is full of bankrupt companies which failed from making the wrong bet. But I'd rather bet on the slower growth pace.
Regarding the flat plateau - Why does the rate stay flat? Because the transport systems cap it. What happens in real life in a situation like this is fairly simple: Wells produce to the transport system's capacity, and that's it. Individual companies will watch their well capacity, and as it declines, they add more wells to make sure they can sell as much as the system will take.
Once a system reaches a certain level (in this case let's say 1 million bpd), the companies involved don't have the driving force to add more capacity because the cash flow deferral is offset by not having to pay a tariff for a short lived transport system. When there's uncertainty regarding the ability to produce at very low rates (and many of these wells will be producing at very low rates) due to oil price volatility, the tendency is to hunker down and defer drilling.
So in conclusion, the flat plateau is a result of a topped out transport system, with individual players deciding not to risk building more capacity.
Governments can also have a say in how this works out, a wise government will deny permits if they think the local infrastructure is being stressed by too much activity, and the ability to hold production may not be there. Which means constraints getting things done may be imposed by local authorities who see us as locusts descending on their land.
Well, that argument works for natural gas but it doesn't work for oil. In our past 150 year history, oil has always been used as quickly as it could be extracted from the ground.
If someone is rate limiting the flow in one location, someone else will come along and increase it elsewhere to try to make a buck. Oil can always be transported by vehicles; obviously for natural gas this cannot be done and it is also hard to store it, so the rate-limiting aspects of pipeline infrastructure are much more clear in the case of NG. Somebody ought to write a detailed post on this to explain it better.
I suspect that completely different dynamics are going on in the Bakken. This might be all a rationalization to explain a way around the poor yields and short lifetimes that we will see.
> Why are all those profiles flat-topped out to 2025?
It should have been mentioned that these guys are adherent of the flat-earth theory ;-)
The way I visualized it:
That line represents a number, $/Bbl, as the price gets higher, the line gets longer and moves down the pyramid.
There may be some debate as to the shape of the pyramid:)
Abundanceconcept - "there is no such thing as uneconomic oil....I thought this was economics 101". That's the trouble with economics! Economists tend perhaps to have difficulty with EROEI. If it takes more energy to produce oil than you get back from it THAT is uneconomic in a real sense. If we ever get to point where renewable energy is so cheap and abundant that we could afford to use it to extract oil with negative EROEI, then pigs will fly and I'll eat my hat.
It depends what that energy is worth. If you take e.g. surplus wind power from the Dakotas and use it to free up oil in shales someplace, even a 0.5:1 EROEI with 2¢/kWh electricity brings you oil at $68/bbl. It might be worth doing this because a lot of the wind power could be sold for much more than 2¢/kWh, and the availability of the dump load allows the wind power supply to be both bigger and "firmer".
Oil is non-economic if the EROI is too low. Economics 101 doesn't teach this. You have to learn that somewhere else. It is closely related to the phenomenon of too high oil prices causing recession and credit cutbacks. Economists are finally starting to pick up on these phenomena.
Technology can bring the EROI of oil up (and the price at which it is economic down). This seems to be what is happening in Bakken. So oil that at one point would have been below the line, can rise above the line.
Gail - Or more simply put: regardless of what was said above about there being no such thing as "uneconomic oil" (because all oil is economic at some higher price) there is uneconomic oil IMHO. It's oil that cost more to recover than society can creat positive value with. Sure: lots of oil to recover at $200/bbl. For those that feel oil would be "economic" at $200/bbl I have a simple question: please outline those industries/users that can take oil/energy at that value and creat something of greater value. Certainly a few would exist. But enough to provide an economy over 300 million American survive within, let alone prosper? Convince me.
Of course, hyperinflation could make it work. Most of could afford gasoline at $25/gallon...when the minimum wage is $40/hr and buger flippers at McDonald's make $75,000/yr. But that doesn't really address the issue, does it?
There certainly does seem to be a price that would make it impossible to sustain the huge effort the current oil producing structure needs to exert. Macro economics would seem to have to acknowledge that, it's not locked into a single econ 101 'guns and butter' chart or is it?
Gail and Rock, I think this is the heart of the matter which separates cornucopians from those who see limits to growth. In following the oil drum for years, never posting until recently, I am amazed how quickly simple ideas can swept away in a tide of endless argument and complexity. I am going to remember this for future reference. Oil that cost more to recover than economic benefit created will not support BAU for long.
Exactly! And I am afraid we are getting to that limit now.
Not only would the (inflation adjusted) price have to be $200/bbl. the oil companies would have to be able to count on the price being at least that high for enough time to scare up the capital and bring the oil out of the ground for a long enough time to retire the original investment and hopefully make a fat profit.
I'm not an oil-patch guy, but I know from what I've read here and elsewhere that oil production can be very risky business.
I would think they will make money any way it turns out.
Don't believe all the stuff you read here. Is this a matter of trading risk for profit? How else does ExxonMobil can generate the most profits of any US company in history?
Down year, yet they are still profitable. Black gold means a license to print money. Name another product that could survive a doubling of price. What product line would be considered more risky given that profit potential?
I suppose we can feel sorry for all the people that lose their shirts or their jobs when prices go up or down, but all of business is getting more and more cut-throat with the passing of time.
Ron - One small picky point I'm sure you appreciate but others might not:"ExxonMobil can generate the most profits of any US company in history". No one knows how much "profit" XOM has made on any of its drilling investments. XOM has a huge CASH FLOW from all its production established over the decades. From a technical point XOM, the corporation, makes little if any "profit" per se. What it doesn't distribute as shareholder dividends it spends on more drilling. What's left after that is held in reserve for future drilling/dividend expenditures.
XOM can look at a field it has fully developed and has a good handle on URR and the apply the monies it spent to do so. They can come up with an estimate of the profit on that project. But that still requires an accurate projection of future oil/NG price. Current high oil prices have certainly improved the profit margin of all producing fields. But it hasn't improved the profit margin on any of the $billions XOM has spent over the decades on failed projects. And not all completed wells will make a profit at the higher prices. Consider the shale gas players. Many have nice cash flows today even after most of the SG wells have declined significantly. But on a net basis Devon and others may not have made a single net $ of profit on their ventures.
XOM has a huge CASH FLOW from all its production established over the decades.
XOM uses accrual accounting, not cash flow. What am I missing here?
From a technical point XOM, the corporation, makes little if any "profit" per se.
I think dividends are commonly included in "profit".
Oil companies tend to use cash flow instead of profits to judge how well they are doing.
The problem with profit/loss statements is that they involve assumptions about what is going to happen in the future. If your assumptions are wrong, you can think you are making profits when you are actually using money. Cash is cash - you either have it or you don't. And if you run out of cash, you are in trouble whether you are making a profit or not.
The point Rockman was making is that ExxonMobile is generating a lot of cash flow, but it is questionable whether it is making any profits or not. That involves assumptions about the future.
That suggests that you think that ExxonMobile is making some wrong assumptions. That surprises me, given how conservative they tend to be.
What do you think those mistaken assumptions are?
Nick - From my perspective I'm not talking about bad assumptions but failures. XOM has a nice cash flow from its successful ventures. But has lost many $billions on dry holes and failed regional plays. When I speak of profit that's what I'm talking about: total investment...not project investment. Several years ago I worked on a dep Water GOM that cost $194 million to drill. Not only did it not find oil/NG it completely destroyed the potential of the rest of the project. That company still had a nice positive cash flow that year. I might make a nice cash flow from dividends and profit when I sell one of my stocks. But if all my other stock investments tanked I made ZERO profit in total. That's the rather simple point I was making about XOM or any other enterprise: one can't use cash flow as an indication of profit or success. Nothing earth shattering in that statement...just wanted to balance the statement regarding xom"s huge cash flow.
And dividends are profits relized by the shareholders...not the corporation. Again, not an earth shattering revelation. LOL
Ditto. And you have to realize that the company's main assets - its oil and gas fields - are steadily depreciating, i.e. declining at a rate of 6% per year or so, higher for offshore fields. If you take the value of that decline out of the cash flow (as well as the dry hole costs) it looks a whole lot less rosy.
In many cases you realize that the company is losing money rather than making it. It is reducing its asset value to zero, and is going to be out of business in a few years.
I used to develop computer software to calculate this kind of thing. Management wasn't really amused when I ended a presentation with, "I've got the results from our new computer software, and it shows that this company has a great future in computer software." They just had no sense of humor at all.
They know that - everyone know that, at least in general. Heck, that's the basis for depletion allowance tax treatment. If they're mis-stating material facts related to that in their accounting, what are they?
Certainly, if they shrink then their revenues will gradually fall, and eventually profits have to follow, but that's different.
Public accounting, of the kind used by companies like XOM, takes all investment into account. Really.
Profits paid as dividends are realized by the corporation, and then paid to shareholders. The level of payout doesn't change the profitability of the corporation.
I think both ROCK and Rocky's angle is that past profitable discovery/development is fueling those profits--the jury is out on how the current/future discovery/development will sustain that flow. If the investments in high extraction price oil don't pay out enough for one reason or another...games up after the older plays are played out. I don't see they are saying any more than that.
That's not how I read their comments. The fact that reserves are difficult to replace is common knowledge.
Re-read what the conversation - there's a suggestion that XOM isn't making money today, based on faulty assumptions. I don't see how unexpectedly low reserves replacement would be one of them.
On rereading I see your point--this is pretty much the take I get, but I may be all wet.
From a technical point XOM, the corporation, makes little if any "profit" per se. What it doesn't distribute as shareholder dividends it spends on more drilling. What's left after that is held in reserve for future drilling/dividend expenditures.
Many have nice cash flows today even after most of the SG wells have declined significantly. But on a net basis Devon and others may not have made a single net $ of profit on their ventures.
There is a huge difference between companies maintaining or increasing their drilling operations with overpriced stock sales (tech bubble style) and an established firm doing the same with its own real profits generated from fully discounted ongoing operations--that looks to be your point--and I have to concur. ROCK seems to lump both types of activity together because from his point of view if what he is drilling now doesn't pay there are losses--old plays are in the past. At least that is how I've interpreted his many forays into this realm.
The assumptions about the future Rocky & ROCK mention are a much more sublime part of the profit and loss statement--much like bad loans on the bank's books that aren't written off inflate the balance sheet and make a said quarter look falsely profitbble, recent bad oil investments that haven't been discounted yet (possibly because a whole set of assumptions that values them is on faulty ground) overvalue the companies current position and can cause profits to be greatly overstated. Considering the time frame involved many years of recent investments in discovery/development that are overvalued could current profit/loss statements as much a fantasy as the ones the banks produced during and after (to the extent the uncollectable loans are still on the the books) the boom.
ROCK and Rocky feel free to chop my head off if I misunderstood you--when I put words in another's mouth I expect to have my head handed to me...I have been married for 26 years ?- )
Luke - Can't cover all the points right now. But let's look at corporate profits. Companies pay taxes on their profits, of course. Are you aware of the truth that public corporations pay almost no taxes? That's isn't to say they aren't successful. Besides expensing the income back into tax deductions they also pay dividends because doing so reduces their taxable income. That's why they pay so little taxes: little taxable income. Between their tax advantages, retained income for future operations and dividens XOM has very little taxable income. And that tells you nothing about the profitability, or lack there of, individual projects. And remember I'm only referring to the oil/NG exploration activities. XOM is a lot more than an oil company. Don't know if it's still true, but about 15 years ago XOM's real estate holding were worth more (much more actually) than all their oil/NG assets.
So maybe Rocky and I confused folks. The XOM numbers thrown out have little bearing on how I'm viewing the oil/NG acivities. Maybe our conversation has gotten confused because some are talking about apples while others are talking turnips.
they also pay dividends because doing so reduces their taxable income.
Really? Are you sure?? If XOM has solved the double taxation of dividends, that would explain why their stock is so popular...
Yes I'm aware of the public corp tax situation
but at least in 2009 big oil did pay taxes, they made up three of the top five tax paying US companies.
Wal-Mart - 2009 Tax Rate: 34.2%
Exxon Mobil - 2009 Tax Rate: 47.0%
Chevron - 2009 Tax Rate: 43.0%
ConocoPhillips - 2009 Tax Rate: 51%
AT&T-2009 Tax Rate: 32.4%
from this Forbes slide show. GE is rated as number the number four US company, but with negative taxes I seperated it from the top of the list.
No. 4: General Electric
Sales: $157 billion
Pretax income: $10.3 billion
Income taxes: (-$1.1 billion)
Tax rate: N/A
can't imagine much money involved in preparing and reviewing GE's tax return, if it were printed out it would be 24,000 pages.
Things have changed a lot since I took my 8 hours of basic accounting in the late 60s but I think dividends are still supposed to be paid after corporate taxes--I thought that was what all the double taxation brouhaha was about (of course I learned back in the day that the idea of double taxing dividends was to encourage companies to reinvest in their own growth before taxes--that must be old school thinking). But then GE did pay dividends in 2009 and it got a tax credit--there are so many turns and dodges out there its crazy.
There is one aspect of oil's production decline that has yet to be addressed: The uses to which oil is put. Some uses will simply be discontinued as we find appropriate or possible substitutes for those uses. This is not to say that we will avoid a crash; we will simply postpone and perhaps soften its coming.
One way of addressing this problem of "discontinuance" is to break a barrel of oil into use percentages--then see what elements we can discontinue or abate. How much of that barrel of oil goes towards plastics. Some uses of plastics will be discontinued for a number of reasons, not just the rising price oil
Just a thought.
stormy - A valid assesment of course. But I think most folks already instinctively know those answers. We see the uses, including "wasteful" consumpion every where. I often drive thru d/t Houston after midnight heading to a drill rig somewhere. A brightly lit Houston (both inside and outside the buildings). Not difficult to recognize consumption that could "discontinued". But it isn't and not for a lack of recognition IMHO. For a variety of reasons we chose to not do what we know could be done. It's a choice...not a lack of knowing it's out there to be done. The waste is not the disease...it's a sympton IMHO.
Human nature is the disease. Find a cure for that and we may have a chance. LOL.
The other thing to remember is that even the "wasteful" uses of oil generate jobs for people. If we discontinue those wasteful uses, then we suddenly have quite a large group of unemployed people to take care of. What do we do to handle them? Raise taxes for unemployment, welfare payments, and Medicaid? I am not sure that the higher taxes would be deemed any more beneficial than the wasteful oil expenditures.
even the "wasteful" uses of oil generate jobs for people.
Reductions in oil consumption would reduce imports. Almost all of the money paid for that imported oil goes to the exporter, so basically none of the jobs lost would be in the US.
Stormy,
Here is my list of oil replacements;
>$20/barrel electric power plants replaced by coal and NG
>$100/barrel use in most low mpg vehicles(vehicles replaced by better mpg ICE vehicles)
>$150/barrel use in most long distance trucking replaced by rail
>$200/barrel use in most ICE cars(except high mpg hybrids) replaced by electric or PHEV.
>$250/barrel use by economy air travel replaced by economy ship/rail
>400/barrel use by sea transport replaced by coal or coal/water fuel.
Would still see first class airline travel and military use of oil >> $400/barrel, some petrochemicals but most plastics and resins can use natural gas, ethanol or acetylene as feed-stock.
Does anyone have this graph but with 2010 on there too?
So many Op-Ed writers like to whine about how Obama has 'caused high gasoline prices by not allowing drilling' . . . . yet this proves that oil production has actually gone up during his term whereas it went down during Bush's term.
(Not that Obama can take credit for that additional oil extraction but it does show disprove that bogus 'Obama hates all oil!' argument. )
spec - So true...just more BS to keep the public in the dark about the reality of our situation. If the feds let us drill everywhere we would we be producting more? Yes, of course. Would that change PO significantly? NO IMHO. The vast majority of viable drill sites are, and have always been, available to the companies. In 36 years I've never been prevented from drilling any of my projects by any govt body. I have had many private mineral owners refuse to lease to me for a variety of reasons. But again, no material negative affect in the big picture IMHO.
@Rockman, But isn't it true that oil produced today was conceived, designed, permitted, drilled, completed and plumbed starting - what - 10 years ago? Put it another way, what exactly is YOUR lag time between acquiring a lease and producing oil in economic quantity (if any) from that land? Given the lag, anything this administration does or doesn't do won't really have an impact for at least another decade on production levels. As an oil man I'm sure you recall the bad old days when oil dipped down to $10.80/bbl during the Clinton administration. About 100,0000 stripper wells were abandoned during that time, many of those folks might wish they hadn't today, but you can't turn around on a dime in the oil patch.
BTW your post on XOM was perfect. Reminds me of something I think I read in Freakonomics, where they talked about drug dealers not really making any money, but just riding big cash flows. So XOM is really a big drug dealer and we're all just addicted to oil...
conceived = discovered
designed, permitted = fallow (the waiting and planning phase)
drilled = construction
completed = maturation
plumbed = extracted
It is easy to see how you can get something like a 30 year lag if 5 to 10 years delay is attached to each of these phases in sequence. Fields in the Arctic lay fallow for many years. Many of the complicated rigs took years to build. Most of the large fields took years to reach maturation as reserves were added. And then the extraction itself has a time constant associated with it. The numbers add up and it seems like a historically accurate way to represent the process.
I have this detailed in The Oil ConunDrum. I am always looking for other ways to explain this model, and it is nice when someone comes along that reinforces some of the premises behind it and so help to build its credibility.
BTW, the Freakonomics duo does not believe in Peak Oil.
smitty - Web gives a great answer. The cornucopians constantly ignore this time lag. Even when a new economic resource is founf it takes decades to bring much of it on line. Another fact they like to ignore: the new resource plays, regardless of how they might ramp of production in the short term, don't have the staying power of typical conventional reservoirs. This was the trap the public companies who were drawn into the shale gas boom suffered. Great to bring on those high rate wells. But their high decline rates required a constantly increasing drilling effort. And for a simple reason: just as Wall Street rewarded these companies as they increased their reserve base, let that reserve base show a net decline and WS will crucify them just as quickly.
This graph is estimated through 2010. I had oil production by PADD through the end of 2010, and used it to estimate the Bakken split. I also had state date through October 2010. The "2009" tag goes with the marker directly above 2009.
Here's another one of these shale plays which sounds . . . astounding. I'm no geologist but the geologic logic sounds sound (hey, that was neat, wasn't it?): This company wants to tap into the source rocks of Prudhoe Bay's oil fields. OK, you gotta figure there's bound to be gobs of oil in Prudhoe Bay's source rocks, no?
Have no idea if this company can pull this off, but they sure are ambitious! And have a *really* long-term time horizon, to boot!
On the peakoil.com forum I started a thread on it here a couple months ago. But just now on Petroleum News' website I encountered this article about this company's plans:
Great Bear raises eyebrows
OK, you gotta figure there's bound to be gobs of oil in Prudhoe Bay's source rocks, no?
No, and any competent petroleum engineer would understand that. Once the kerogen in source rock is cooked to crude oil by heat and pressure, it starts migrating. And it keeps on migrating until it is trapped in an oil reservoir or escapes to the surface.
There's no point in looking for the oil in the source rock because it's not there - it's in the reservoir rock. Knowing the location of the source rock is useful but only from the standpoint of knowing where the oil might have migrated and looking for reservoirs there.
One more point - source rock is generally impermeable, so you couldn't get the oil out anyway. Porosity and permeability are key features of good reservoir rock, and that's why oil companies look for those features in oil reservoirs.
The Bakken Formation in North Dakota is something of an exception because the source rock is more or less the same as the reservoir rock, but this is an unusual exception.
That is what I was implying elsewhere in this comment thread. The aggregation mechanism is close to being "in-place" so the categorization is different for Bakken. I could also ask whether it is one large dispersed reservoir or thousands of mini reservoirs with localized collection regions?
I could also ask whether it is one large dispersed reservoir or thousands of mini reservoirs with localized collection regions?
Well, companies are looking for the "sweet spots" in the Bakken which are profitable to produce, so I would say it is really thousands of mini reservoirs. Most of it is uneconomic to drill.
Have you been reading anything in this thread? I've got a list above of a half dozen shales where they're already producing oil from, or large quantities of in-place oil have been proven.
Bakken
Niobrara
Eagle Ford
Monterey
Tuscaloosa Marine
Utica
I can also show you one in Australia, and one in France, and at least a couple in Canada. There are bound to be more, possibly many more. The Bakken is not all that unique.
a-c - Hopefully Rocky can chime in because this play is closer to him. But the fact they toss out $10 million/well totally destroys their credibility IMHO. At the height of the boom that's about what wells in Texas cost. And no one can drill anywhere in the world cheaper than we can here. Just my WAG but I would guess their wells would cost many times that $10 million.
One more little detail: the drill rigs they would use...they don't exist. Their construstion and transport to the Arctic would costs billions. Notice they don't mention who will be investing this capex. No drilling company would undertake such expansion without a gold plated gaurentee that all those wells would be drilled.
I'll take a chance with my credibility and guess that this is just a world class investor scam worthy of Bernie M. Where can I send my money?
@ROCKMAN,
What I've been reading about well costs in the Bakken is that nowadays they run around $5-6 million apiece. If you've got info to the contrary, I'm all ears. No one doubts Alaska is going to be more expensive, but that's why $10 million apiece seems like an OK guess, maybe.
I would presume they're assuming this is going to be the ultimate in mass-production, cookie-cutter, large-scale well production, so perhaps they're assuming there'll be significant economies of scale.
Don't get me wrong - as I said in the initial post I'd be surprised if they can pull it off. But the bios of the guys doing this (see peakoil.com thread I linked) don't sound like they're a scam. They already plucked down $8 million for the lease. So, you never know.
The Bakken play only works because companies can drill some very cheap wells in North Dakota, and do extensive frac jobs on them for a low cost.
As Rockman says, he can't drill a well in Texas for much under $10 million. You can't drill a well in Alaska for anything like the same low cost as Texas. It will probably closer to $100 million to drill that same well in Alaska. The costs up there are incredible because you can't just drive around in trucks on roads and set up drilling rigs like you do in the lower 48 states. There are no roads, no gas stations, no stores, no hotels, and the ground is unstable. Vehicles sink into it.
I don't see why the source formations under the Prudhoe Bay field would be anything other than normal source rock. I don't see why the oil would still be trapped in them like a Bakken-style play. I would think it would have moved on and be gone. I'm with Rockman, I think it smells fishy.
Read the whole thing
And confirmation from another person.
In these articles the source rock is being compared to the Eagle Ford shale. If you want an example of what the Eagle Ford shale is already doing, go to the EOG Resources latest quarterly presentation (PDF) and read through pages 10-13. Plenty of wells with IP rates of several hundred to 1000+ bopd.
Here's another example - the Monterey shale in California.
LINK
From the article abundance linked:
Great Bear is NOT looking for investors or partners, except for a possible shared 3-D seismic shoot next winter across the North Slope from the border of ANWR to the far western edge of the National Petroleum Reserve-Alaska, out into the Beaufort and Chukchi seas
ROCK you know a bit more about 3-D seismic than most who comment here, isn't that a rather large except for?
this baffled me as well
In phase one, the spacing between the wells (about eight to a pad) will be 160 acres. In phases two and three, the company will use the same one-acre pads it used for phase one, but it will likely reduce spacing between wells to 80 acres, Duncan said, in phase two.
either I've become very dense--or something is very convoluted in that paragraph.
Luke – If they are at the phase of fishing for seismic $’s then they are a very, very long way from drilling for oil let alone producing. Interesting that they already have a very detailed development drilling program given that they haven’t even raised the money to shoot the seismic which would be a critical component in determining a development drilling program.
I don’t fault these guys that much: many rank wildcats are offered as completely “Blue Sky” opportunities. IOW there’s $billions of profit to be made…unless of course the plan fails in which case you lose all your investment.
Well, yes, if they haven't even shot seismic yet, their geology is at the "wild guess" state. As far as I can tell, this company has never drilled an oil well before, so their cost estimates may be based on nothing but hot air.
I can't fault them for wanting to drill a rank wildcat. Many people have made a lot of money that way. But many more have lost all their investments.
Guys, you can speculate all you want about whether these guys will be able to pull this off or not - and as I said, I'd be as surprised as anyone if they do. But looking at the CEO's bio on their website, you can't say these guys don't know what they're talking about. The CEO has been working on the North Slope for "big oil" for decades:
http://www.greatbearpetro.com/management-ed.html
One of the articles I linked above has more on the team there.
a-c - Never doubted anyone's experience or abilitites. But I've got half a dozen equally promissing projects just as Rocky probably has. All we need is someone to float us $50 million and we'll get right after them.
My point was that shale evaluation on the N Slope is probably a good 10 years from having a serious discussing about (if ever) IMH0. I wasn't speculating about their chances of success in commercially producing shale up there. I was speculating about the low probability of anyone funding the seismic. I was stating a fact: they haven't even begun the process yet so there is nothing to speculate about with respect to the potential up on the Slope. We can pick back up with a meaningful discussion after they (or anyone) drills and tests the first N. Slope shale well.
Supposedly they're going to drill their first well sometime this year. I'll keep y'all updated. :-)
ROCK, did you happen to check the size of that shoot on a map? The scale line on this one should show 50 and 100 miles. The area is over 350 miles across and 100-200 miles deep.
Shell spent two or three entire summers fighting windblown ice pack in the Chukchi and the Beaufort, so I'm guessing these guys only plan to go out as far as the ice will allow in the winter.
Any guess on how much such a 3-D shoot would cost? I'm guessing its not a one winter project unless an ungodly amount of resources were brought to bear. Looks to me like Duncan is trolling for a great big fish.
The article is pretty much a summary of a two hour presentation to the state legislature--they get a number of them (usually one hour but I'm sure the Senate Resources Committee was all ears when someone said we can refill the pipeline). Most but not everyone is angling for some sort of tax break, feasibilty study grant or loan guarantee--these presentations get broadcast on public TV as well so the presenter gets a somewhat wider exporsure but I haven't been watching much yet this session.
I still don't understand that paragraph about well spacing--I think the reporter buggered it up some. 160 acres between wells, 8 wells to a pad, but the pads are 1 acre. Is a 160 acre grid with a one acre pad on each corner what is meant? Why would you do that if you are running 4000-6000 foot long laterals?
This is entirely on land.
EDIT: Here is a map of their acreage:
LINK
I just found an online video of the presentation to the Alaska Resources Committee. You have to put up with one other (unrelated) presentation first, but then Great Bear gives their pitch:
http://gavelalaska.org/media/?media_id=SRES110226A
I have DSnail so I won't be loading a two hour plus video, but thanks--other will.
I'm talking about the 3-D shoot. From the article again
Great Bear is NOT looking for investors or partners, except for a possible shared 3-D seismic shoot next winter across the North Slope from the border of ANWR to the far western edge of the National Petroleum Reserve-Alaska, out into the Beaufort and Chukchi seas
my emphasis. What part of out into the Beaufort and Chukchi seas is entirely on land?
Again the well spacing:
In phase one, the spacing between the wells (about eight to a pad) will be 160 acres. In phases two and three, the company will use the same one-acre pads it used for phase one, but it will likely reduce spacing between wells to 80 acres, Duncan said, in phase two.
makes no sense to me as written--see above comment to ROCK.
There may be something too all this, maybe quite a lot--but these guys just started up and sunk nearly $9,000,000 into North Slope leases. Their second round of financing from 14 investors was $6,000,000--your mission, if you decide to accept it, is to find out what their first round of financing was.
Apologies, I missed the "out into the Beaufort and Chukchi seas" part. Not sure why they want to go that far since it's far from their acreage, but, whatever.
either Duncan really got carried away shooting from the hip at the presentation or ownership of that seismic data is a key part of their business plan--the scope and cost of that data gathering operation may well make it far more than a whatever.
How you doing on finding out the size of their Great Bear Petroleum's first round of financing? It would be really nice to know just what percent of their capital they have tied up in the $9,000,000 North Slope leases. I'd look but the sun is shining strong and its almost up to 20F, time for me to put on a little softer glide wax.
Later <?- )
Don't know about their first round of financing, but they just raised another $18 million today:
LINK
Luke, the drilling pad itself is one acre. This is the surface area taken up by the pad, which has to be built up from the tundra. The pad surface requires permit, and state authorities worry about the development footprint. Once a pad is drilled, you can theoretically drill 1 mile long horizontal wells from the pad. To keep this simple, this would give each pad a one mile radius circle footprint at the reservoir level, or Pi Square miles. That's pi*640 acres, or 250 acres per well if 8 wells are drilled in a radial fashion. But the wells would likely be drilled in "opposing forks" patterns to make sure they intercept the fracture patterns, which reduces their overall coverage.
These guys' thoughts are fairly simplistic at this time, in the end, the patterns do have to take account of the fracture system orientation, and the overall pattern is constrained by the turn radius for the outer wells (the outer tines in the fork).
Luke - to shoot that entire area (at onshore Texas prices) it would run around $190 TRILLION. Of course it would cost several time that up there. Needless to say no one is proposing to shoot a very large portion initially. I don't want to sound to negative but for those shales to be commercial they have to yield oil at rates many times what the best Eagle Ford wells are doing because of the very high costs to drill up there. IOW the play will have to be several times more valuable than any shale trend ever discovered. Not saying it's impossible...just damn near impossible IMHO.
Thanks ROCK, that'a an awful big fish indeed--Duncan might be trying to get the state to rise to the seismic bait, it certainly has interest in knowing what its got, that's just conjecture on my part though.
I've watched a couple presentations given to the resource committee--they were big ideas with nice charts, I didn't hear where any of the money was to come from much less how it crunched out.
I have to agree--no way North Slope oil will be as cheap to get as Texas or Dakota oil. John M. Miller (formerly of ARCO I believe) has a bit to say about the cost of doing oil business in Alaska his recent book The Last Alaskan Barrel: An Arctic Oil Bonanza that Never Was
But Duncan says they are drilling and he expects production by 2013. I'm guessing he's just going punch a hole into the side of the pipeline to ship it <?- ) Actually Duncan's point about access seems valid sort of--don't know if he will have summer road access to all his pads--they are all about winter ice roads up there. Pipelines go up in winter too. I wonder who fast tracked all the environmental impact work for all the pads (and access) he hasn't built to get the oil the location of which he isn't exactly sure of. There is only one winter between now and 2013.
There seems a bit of hyped up optimism there for sure. His thoughts on percentage recovery.
We’re using 5-6 percent [recovery] as our base case today. My suspicion is … it will be higher than that by the time we drill our full production test next January.”
On the other point:
I gave that drilling scheme some thought on the ski trails--I came up with one that at least used the numbers given--but its a whole lot of pipe. Are they proposing eight mile or so long lateral runs extending from one side (or four from each side it could be space the same) of each of the half mile apart one acre pads? If all runs aligned on the same axis each pad's runs would extend past the nearest row of pads up to the next row of pads over. You'd get a 8 lateral runs every 1/2 mile or more simply, lines of pipe about 330' apart.
Then in phase two moves the pads over a 1/4 mile and does it all again which if the horizontal run where all at the same depth (just guessing they would be--but maybe thats a bad guess) and if they all ran the same direction (just guessing the fractures they are trying to intersect would be mostly parallel) you end up with a pipe every 165' feet. That seems like it would count on a fair amount of oil flowing for a while to pay it off. Is that sort of drilling scheme used in shale? I really have no idea how much iron we are sinking into the earth in these fields.
As Miller says in his book, The Last Alaskan Barrel: An Arctic Oil Bonanza that Never Was
And this is what people with these pie-in-the-sky dreams about Arctic production don't realize - it is very, very expensive to operate in the North, and your chances of recovering your investment are very poor. You can't simply take cost and profit numbers from the lower 48 and apply them to Alaska. The much higher costs will kill your chances of making a profit.
I haven't picked the book up yet but I do plan to read it. Now that stint of $10-12 per barrel in the 90s didn't help the over all and it seems ARCO was gobbled up right after that--could be some sour grapes in the book. If I recall (from a review in our local paper) Miller was pretty high up the ARCO feeding chain.
No doubt if Arctic oil began being shipped in say 2004 the story would look different. Do companies come out better when there holdings get nationalized in a place like Venezuala? I don't know just asking. It's risky out there.
The much higher costs will kill your chances of making a profit.
So do you think the North Slope--the play that has been producing since 1978 not this shale dream--if done in today's market, both development and sales, would be higher risk than deep water Brazil?
Of course the markets were optimistic and pushed production back in the late 70s, that blurb of oil coming on line then encouraged the US oil policy--burn it all as fast as we can. But that all is beside the point for my question.
again:
Do you think the North Slope--the play that has been producing since 1978 not this shale dream--if done in today's market, both development and sales, would be higher risk than deep water Brazil?
Do you think the North Slope--the play that has been producing since 1978 not this shale dream--if done in today's market, both development and sales, would be higher risk than deep water Brazil?
Probably. The technology for deepwater offshore is highly developed at this point in time, and it is a relatively straightforward process to drill in the relatively benign waters off Brazil. You can take the oil off the platforms with tankers and deliver it anywhere in the world. OTOH, I don't think Arctic drilling has gotten any easier, and building the Trans-Alaska pipeline would be proportionately more expensive due to the increased environmental regulation.
Looking at Continental Resources’ (CLR) and Brigham’s reports we find one excellent consistency and a couple of major inconsistencies.
Brigham’s average production of 1800 b/d for the first week, 1100 b/d for the first 30 days, and 830 b/d for the first 60 days falls on a smooth curve that includes CLR’s 450 b/d for the first 90 days. This curve implies a production rate of 90 b/d at the end of the first year, only 5% of the first week’s average production rate.
If we take a production rate at the end of the first year of 100 b/d, declining to zero at the end of the 10th year, we have 165 kb for those 10 years. Add in the 75 kb from the first year and we have 240 kb EUR. This is a long way from the 300 to 400 kb EUR projected by CLR in their EUR vs frac stages chart. Their median EUR projection seems to be about 360 kb which is still high vs the decline curve, but much lower than the 518 kb they have modeled. Very strange.
I have tried curves using the 30, 60, and 90 day average rates as end of period rates, or as average for each of the first, second, and third 30 day periods instead. Thus I have a range of EURs from 240 to 410 kb, with a middle value about 340 kb. However the low end is the one consistent with both companies’ real wording. The safest EUR number to use is probably 250 kb/well.
In their curve of IP vs EUR Continental shows a first 30 day IP of 600 b/d corresponding to an EUR of 500 kb, and a 30 day average IP of 1000 b/d as an outlier vs 1100 as an average for Brigham. However a 30 day IP of 600 subtends a 90 day average production a long way below 450b/d, and therefore a much lower EUR. CLR’s EUR estimates look totally unrealistic, and inconsistent with their other data.
There is a lot of inconsistency in the Continental data. Their 30 day production rate curve vs frac stages must be for a lower producing set of wells than the 90 day curve. Both curves suggest that anything over 18 stages is well into diminishing returns. Near 15 stages looks optimum.
From Nov ’09 to Aug ’10 CLR has gone from 4 to 18 rigs, and from about 25 to about 33 “days on well”, about 10 wells/rig/yr at end 2010. Elsewhere they report 800 “gross” wells for 562 “net” wells. This would suggest 30% non-producers, , ie 7 producing wells per rig per year. With 164 rigs in Q4 2010, one would expect an average of at least 120 for the year, providing less than 700 new wells. A judgment call would suggest 6 producing wells per rig per year.
CLR then shows about 2300 wells producing in the Bakken at mid 2010, of which 2075 are horizontal multi frac wells. 2300 wells produce about 350 kb/d at end 2010, or 150 b/d/well. It looks like there were 400 wells added in 2007, 550 in 2008, 500 in 2009, and > 600 in 2010. An average production in the first year of 500 b/d/well, declining to 160 in the second year, 80 in the third year and 65 in the 4th year, etc., would give us near 150 b/d/well at end 2010, which is consistent, and is also consistent with an EUR of about 250 kb/well. So we now have some numbers to project future growth in output.
CLR claims there were 164 active rigs working in the Bakken in late 2010. If we add 60 rigs per year to 2020, and maintain 7 wells/rig/yr, and if my calculation is correct, we would be producing 3 million barrels/day in 2020. If present production declines by 4%/yr through 2020, we would have a net gain in output of 0.5 million barrels/d to offset declining imports, 10% of the expected decline if we are lucky.
Murray, Gross Wells means actual wells drilled, net wells means net working interest wells drilled (ie Gross wells times their net interest in the well population). The proper approach to describe wells which behave this way is to use a hyperbolic decline curve, but they don't have the information (and may lack the know-how) to describe the curves.
My conclusion? These companies don't have the information to project what's going to happen in the future. Neither do we. Knowing human nature and the types who roam board rooms when they are peddling stock, I tend to believe we are seeing a lot of hype.
I also keep repeating, how do they think they are going to move these huge oil volumes to large refining centers?
Please note my capacity additions in my post above
BTW, speaking of large projects, here's Chesapeake Energy's announcement of its JV with CNOOC in the Eagle Ford from last fall:
Chesapeake Energy Corporation and CNOOC Limited Announce Eagle Ford Shale Project Cooperation Agreement
There are a lot of other players in the Eagle Ford, so one would presume the total amount of oil coming from there will be larger than that. I know EOG is really big on the play too.
As always Gail, thoughtful and well observed writing...and you really put it exactly correct with this statement:
"It seems to me that whatever additional oil and NGLs are produced will have a much bigger impact on the US economy than it will have on “peak oil.”
EXACTLY CORRECT.
Once more we must confront the "math", IF we accept the models as given by Campbell, Simmons, Mearns, Westexas, Deffeyes, etc.: We could stop every car and truck in the U.S. and burn it where it stands, and it would have essentially NO real effect on peak oil, and very marginal effect on global warming. And in comparison to the world, U.S. oil consumption is now "consumption at the margins" of the debate, and becoming less of a factor (to say "more marginal") everyday. But burning every vehicle in the U.S. while having essentially no impact on "peak oil" would have a CATASTROPHIC impact on the U.S. economy. In my 5 years as a registered poster on TOD, this realization alone has been worth the price of admission for me (oh, that's right, the price of admission is free...:-), but it is still a great realization that does not even register on the radar of most minds even in tghe peak oil community.
RC
Bingo
Eliminating 11M bpd of consumption would have no real effect??
Further, if we were to replace every car and truck in the U.S. with PHEVs, EREVs and EVs we would not only eliminate 90% of that 11M bpd, but we would also create the means for the rest of the world to eliminate the majority of their consumption.
To paraphrase Cassius: "The problem, Dear Brutus, lies not in our Stars, but in our internal combustion engines."
I like "infernal combustion engines".
They come with fool injection!
:)
"Eliminating 11M bpd of consumption would have no real effect??"
Notice what I said in my post: IF you accept the models of most of the peak oilers, they are talking about descent in production anywhere from 20 to 50 percent, never to rebound. If we take current world production at aound 80 million barrels per day, then only a 10% decline would be getting close to all the American market consumes. A 20% drop in production would mean that no matter how fast we saved oil, we could not stay up with the depletion treadmill. A 20% drop year on year for only a couple of years would mean the lost production would vastly exceed the amount of oil we are burning in the U.S.
If we accept some of the so called "export land models" talked about often enough on TOD, we would see declines in oil exports meaning that, according to some, half the oil in the world market now would become unavailable, and again, with no chance of recovery. What we can see is a clear picture, IF you accept the scenarios of Dr. Colin Campbell, Matthew Simmons, M. King Hubbert, Kenneth Deffeyes, and here on TOD, Euan Mearns, Westexas and other peak oil luminaries, then no amount of savings by the American driver or consumer can overcome the peak oil catastrophe. Notice I say IF you accept these scenarios, and if you are a frequent visitor here, you probably do.
As far as replacing the burnt automobiles, why? The economy would be in a shambles, there would be no real consumer spending, who would buy any of the replacement automobiles? The very core of the peak oil theory pretty much spells the end for privately owned autos of any kind.
It is very much the scenario as expressed in "How I Learned to Stop Worrying and Love the Bomb". IF you accept peak oil scenarios as expressed here and IF you accept ELM (export land models) this game is over. Go out and buy a Porsche or Rolls Royce and enjoy life, you can do so with no guilt knowing that what Americans buy and drive matters only to the economy of America, for awhile, and to your own personal economy...for awhile...there is a way in which "peak oil" is the most liberating philosophy in world today. :-)
RC
You've raised several points, but let's address one at a time:
the models of most of the peak oilers, they are talking about descent in production anywhere from 20 to 50 percent, never to rebound.
Over what period of time? Aleklett is projecting an 11% decline in all liquids (adjusting for BTU content) from 2010 to 2030. The annual decline at the end of that period might be 3%.
And what about the shale oil that is the subject of this Post? It appears to exist around the world, and be economic at $50 oil. How does it raise projections? I hear many times on TOD about various developments that "it won't prevent the peak, it will only reduce decline rates", but reducing decline rates would make a huge difference.
If we only have a 3 percent annual decline rate then the whole point becomes moot...demand will fall faster than that...and replacement by use of natural gas and even some efficiency improvements would cover that easily...most of the developed world is already seeing demand side drops greater than that, and the demand side drop will accelerate with new technology.
RC
I agree.
Suggesting that China and India will not have (strong) growing oildemand this decade ? If you look at their 'economic growth plan', how many new planes they buy, how many new roads constructed to be filled with ICE cars because of a strong growing middle class. We are talking here only about 2 growing countries together with more than 2 billion people.
New Chindian demand will be a problem, no question.
I'm not so worried about planes. Cars are a problem, but keep in mind that Chinese drivers tend to drive many fewer miles than US or even European drivers.
China is pushing PHEV/EREV/EVs very hard. Chinese electric bikes sales are twice as large as car sales.
A substantial portion of Chinese oil consumption is for diesel electrical generation: we can expect that to go away.
Why not ? It's not only about fuel use, but also on what economic growth is based. If they invest in thousands of planes that later cannot fly (enough) and invest in useless infrastructure there is a big problem. Comparable with all those workers that keep on building homes,etc in China. That bubble is going to burst.
Not bad, but in a country with more than 1 billion people the absolute numbers are important also.
No doubt, especially when more and more heavy oil is produced, which seems to yield much less diesel.
If they invest in thousands of planes that later cannot fly (enough) and invest in useless infrastructure there is a big problem.
Flying will outbid other uses. If fuel is 40% of aviation cost right now, then a doubling of fuel costs will only increase ticket prices by 40%. That won't kill flying.
Hasn't a barrel of oil a certain percentage kerosene yield ? And the most with light crude ? Probably you think that flying slower will be a long term solution.
No, but the projected increase in Asia is impossible. Will be hard for the manufacturers and many people who think of getting a job in the aviation industry.
Hasn't a barrel of oil a certain percentage kerosene yield?
Not really - refineries can shift their yield between different products.
In the medium long term, aviation can increase it's efficiency dramatically, by 3x. In the very long term, it can go to other liquids, like hydrogen.
the projected increase in Asia is impossible.
What is the projected increase, in terms of pax-miles? How does it compare to the industry total today?
In the medium long term, aviation can increase it's efficiency dramatically, by 3x. In the very long term, it can go to other liquids, like hydrogen.
No, it can't increase efficiency and no, it can't fly on hydrogen.
Sure it can.
First, while jet fuel is probably the hardest use for oil to replace, there are a number of ways to use it more efficiently. Short term changes include buying more efficient planes; reducing use of older, much less efficient planes; filling planes more fully; longer and more gradual descents, reducing powered flight time; reduced time in the air waiting to land; electric "tugs" on the ground); and a long list of others - ( http://www.nytimes.com/2010/10/09/business/09air.html?_r=1&th&emc=th ). This might be expected to reduce fuel costs by roughly 1/3.
In the long term, design changes can reduce fuel consumption by 70%:
"CAMBRIDGE, Mass. — In what could set the stage for a fundamental shift in commercial aviation, an MIT-led team has designed a green airplane that is estimated to use 70 percent less fuel than current planes while also reducing noise and emission of nitrogen oxides (NOx). http://web.mit.edu/press/2010/green-airplanes.html
and
"the team has found that the SUGAR Volt concept (which adds an electric battery gas turbine hybrid propulsion system) can reduce fuel burn by greater than 70 percent and total energy use by 55 percent when battery energy is included. Moreover, the fuel burn reduction and the ‘greening’ of the electrical power grid can produce large reductions in emissions of life cycle CO2 and nitrous oxide. Hybrid electric propulsion also has the potential to shorten takeoff distance and reduce noise. "
http://www.boeing.com/Features/2010/06/corp_envision_06_14_10.html
Interesting article. They could take flight in 2035. But what if Aleklett's prediction for 2030 is way too optimistic, as some say ?
Other efficiency measures will normally be offset by a rising amount of flights (in China they are building a lot of airports). I think the strong companies will do their flights almost as usual in the future and a lot of small companies will go bankrupt. Making more kerosene out of a barrel of oil makes little sense in a world with competition between the different oil products.
what if Aleklett's prediction for 2030 is way too optimistic, as some say ?
I haven't seen anyone seriously question Aleklett's prediction for 2030. I've raised it a number of times on TOD, and discussed it with people like Gail.
Keep in mind that it includes all liquids, unlike many analyses on TOD. Analyses of crude only (or C&C) are very useful building blocks, but ultimately it's the total supply (corrected for things like BTU content) that matters.
Do you remember what you're thinking of, and what the objection was?
If the amount of oil drops below the minimum for the Trans-Alaska Pipeline System, could they can add a diluent to the oil from tanks on the Alaska side, separate it at the other end, then pump it back to the Alaska tanks in batches?
Wouldn't seawater be the logical diluent?
I'm a bit confused, the entire TAPS is in Alaska--which side are you refering to as the Alaska side--I'm guessing you mean the arctic side <?- )
The oil used to take four days to travel the 800 miles, now it takes thirteen--the oil is quite a bit colder by the end of the trip now than it used to be. The slower the flow the less friction heat added and the more time the oil mass has to cool. More wax is forming on the cooler pipe now. They used to run a pig down to scrape out the wax every several weeks, now its every four to seven days.
I've not heard anyone suggest diluting the oil flow with seawater until just now. There is the heat issue you know--at some flow level sections of the pipeline will drop below freezing unless the oil is reheated--can't imagine seawater would stay very warm on two week trip when it starts out at near freezing in the arctic ocean.
If memory serves, it was biproducts of bacteria in seawater pumped in to pressurize the BP side of Prudoe that exacerbated some of the corrosion problems--but that might be 'urban' myth and right now I' not running it down.
I've been hearing concerns about the flow through the TAPS dropping below a critical level for some time.
The idea of adding something like seawater to keep the flow volume up seems blindingly obvious, now that someone suggested it. I can't believe people involved with the operation haven't thought of it long ago. That suggests to me that they're not worried about the problem, and that the whole thing is a tempest in a teapot.
As far as the heat issue goes: it would only require one barrel of seawater per barrel of oil to double the volume going through the pipeline. Heating up one barrel of water by 100 degrees F would only require 30,000 BTUs (42 gallons x 7 lbs/gallon x 100 degrees) - that's only about .3 therms of natural gas, or about 12 cents worth.
Similarly, you could pasteurize the water by raising it to 160 degrees, which is a temperature difference of only another 30 degrees.
I've never heard of using seawater as a diluent. You have to realize that water and oil are immiscible and would immediately separate in the pipeline. The water would drop out, collect in all the low spots, and freeze there. Most likely it would completely screw up the pipeline so it would cost a fortune to get it started again.
That certainly makes sense. I've been hearing about Texas oilfields with 99% watercut for a long time - for a moment there I forgot the oil was floating on top of the water coming from below.
hmmm. No way to emulsify the oil - add a little detergent?
Why couldn't the water be heated sufficiently to prevent freezing? I suspect water holds more heat than oil.
Any thoughts about other diluents?
Nick, a water and oil emulsion forms around 50 % water cut, and it has a higher viscosity than the oil. So it takes more pressure to pump it down the line. There are emulsion agents, but when the stuff gets to Cook Inlet it has to be separated, and it would cost a bundle. Then there's the density issue - the mix has to come downhill once it crosses the pass, and this requires pressure reduction.
I think there are possible solutions, but adding water to the line sure sounds impractical.
it takes more pressure to pump it down the line.
How much more?
when the stuff gets to Cook Inlet it has to be separated, and it would cost a bundle.
I guess the question is - how much is a bundle? How does it compare to the alternatives? For instance, I'm struck by the low cost of heating discussed above.
I think there are possible solutions
What do you have in mind? Overall, do you think that we should be highly concerned about dropping TAPS flow levels?
I think there are possible solutions
What do you have in mind? Overall, do you think that we should be highly concerned about dropping TAPS flow levels?
If you check out the pdf doc I linked and buy into the 200000 bpd lower flow limit (it assumes some tech solutions I'm sure) TAPS stays viable until about 2040. The plays under development on the chart are expected to minimally extend the pipe life past that.
It would be great if someone more tech savvy than myself--like maybe WHT--would grab a couple charts off that report and post them here. The charts are germane to this entire set of threads. I promise I'll learn to work with pdf images--right after I convert my big paper weight of a pellet boiler into a useful piece of equipment<?- ). Once pdf charts get posted in these threads even a simple guy like me can bring them forward as needed <?- )
thanks KODE, an editor would have done it cleaner but this works
The planned production profile of the Great Bear project would look like this:
Got it from this PDF
BTW, when you take a screen shot like that, you can re-size the image in Paint or The Gimp to get rid of all the extraneous stuff. It's real easy in Paint.
Assuming it's just an off the chart shale play--no seismic, no holes yet drilled, just some generalizations about the formations from some old holes somewhere nearby and a flexible drilling plan, that is quite an assumption--well that is moving real, real,real fast for the North Slope--200,000 bpd before 2017.
In November they told Petroleum News they wanted to drill two test wells this winter--have they said how that is going?
I actually havent't been on the ground where Great Bear's leases are. I've worked both north and south of them, but not as an oil guy. They must have a heck of a fast track for permitting--200 wells a year at 8 a pad is 25 one acre pads a year. There would eventually have to be an entire set of handling facilities tied into the pipeline at the play but until then the oil will have to be trucked to the facilities up north at Prudhoe to get shipped.
That means right off those pads either have to be connected by feeder pipeline or permanent road to the haul road to get that oil out. Arctic roads over permafrost are never a small task even if you manage to get the permits. That's a lot of gravel. They'd best have all their ducks in a row so they can start stockpiling this summer--if they can get gravel somewhere nearby they will be allowed to drive to in the summer. These guys just got here. They think they will be up and running the winter after next. WOW
We haven't even mentioned the water issue--these will be intensely hydrofracked horizontals. Never much issue getting permits to take a bunch of water out of Alaskan Rivers--just run over to the DNR and tell them your gonna take it--they won't want any detailed environmental studies. Just ask the guys trying to develop Pebble Mine. The North Slope is dry country--there are sometimes issues about getting enough snow to build ice roads. Its just a tough tough environment to get things done quickly in. You have to throw a whole lotta money at it and and hope you planned right.
2013 as a production date with 200,000 bpd by 2017--it's a lot easier to sit down an draw the chart than to get it done. That's a heck of a schedule to set before sinking a single pipe.
Well let's try that again. Sorry about that novice mistake up there editor--I deleted a chart I originally posted after I cropped it--I thought it would just end up a little box with an X in it oh well
If you buy into the 200000 bpd lower flow limit (it assumes some tech solutions I'm sure) TAPS stays viable until about 2040. The plays under development on the chart are expected to minimally extend the pipe life past that.
For good measure here Alaska's production is added to the lower 48
Thanks.
It looks like we'll have TAPS for quite a while.
There is interest in The Slope's traditional oil and gas--Repsol (Spainish Co.) has been investing in less stable regions of the world of late. From today's News Miner
We wanted to balance our portfolio with assets which are in places that are stable in political and legislative terms and also where the exploration risk was lower ... ” Rix said. “Alaska fitted both these premises perfectly
Rix said the company’s $768 million exploration plan represents the “minimum” it expects to spend. “Depending on the results, extra spending would be allocated according to the needs identified,” he said.
Repsol said its partners are an affiliate of Armstrong Oil & Gas, known as 70, and GMT, both based in Denver. It said both have been active explorers on the North Slope and are two of its largest lease holders
As to the seawater emulsion, what fun it would be at Valdez, even if they could engineer a way to make it flow there cheap enough and not tear up the pipe and such in the process. Not a lot of flat space on the steep mountainside where the marine terminal sits ($$$). The Arctic Ocean water removed would have to be clean enough to dump in Prince William Sound--just a tad tougher operation than cleaning ballast water.
Could be just a few reasons no one has suggested the seawater dilutent process yet. I haven't got far enough through the pdf report to see what assumptions were used to establish the 200,000 bpd flow minimum. Recent articles suggest 300,000 bpd as a likely tipping point.
I think osmotic filtering only costs about $.001 per gallon of water, or $.04 per barrel of water. Given that doubling flow volume would only require one barrel of water per barrel of oil, a filtering cost of 4 cents per barrel would have a pretty good $-ROI.
Oil in water emulsions are being studied as a way to dilute heavy crude. Here is an article behind a pay wall on the subject. My guess is if it does prove feasible for long cold lines the cost per barrel will have plenty of steps to take into account.
Your quoted numbers likely include only operational not capital costs. The reverse osmosis process you mention would be the last step near clean water made on exit and possibly before entrance into the Trans Alaska Pipeline System--250,000 bpd of salt water might not be anything they would want to chance running through a fifty year old 800 mile long pipe.
But if oil is +-$200/bbl in today's dollars by that time lots of stuff may be on the table. We will see how the oil price/economy strength seesaw goes. WTI crude is $105 a barrel today.
Your quoted numbers likely include only operational not capital costs.
Well, wikipedia gives costs for operating multi-stage flash distillation desalination plants of about $.002 per gallon ($.53/264 gallons), and reverse osmosis is supposed to be cheaper...
http://en.wikipedia.org/wiki/Water_desalination
the mix has to come downhill once it crosses the pass
which pass--the pipeline crosses four substantial mountain ranges
Its highest point is at Atigun Pass, where the pipeline is 4,739 feet (1,444 m) above sea level. The maximum grade of the pipeline is 145%, at Thompson Pass in the Chugach Mountains from here in wikipedia Technical Details heading
That steepest grade is what the oil is headed down as it comes into the Valdez marine terminal. Right now I believe half or so of the pumpstations are mothballed as the lower oil flow and better pumps have made them superfluous.
This 2009 report on North Slope gas and oil potential has a nice chart on page 1-5 stacking individual field production out past 2050. It has a 200,000 bpd line indicating minimum pipeline flow. I'd have posted it but its pdf and I haven't looked into screen capture + GIMP yet <?- )
Very simple:
Somewhere on your keyboard there is a "Print Screen" key (mine says "Prt Scr"). Pressing it will put a picture of your screen in your clipboard. Open your favourite graphics editor (GIMP is an open-source heavy duty one), paste, and edit.
Or if you are good with reading PDFs in your browser, use Firefox and install the FireShot plugin.
If you're trying to keep it warm, that's a feature; viscosity creates friction which generates heat. If e.g. alcohol can be added to keep the water from freezing, it would be a lot better than adding seawater (which only depresses the freezing point to -1.8°C).
The advantage of seawater: it's a little cheaper and easier to obtain. OTOH, I suppose eliminating the corrosiveness of seawater would be worth a little purification.
I'm surprised TAPS isn't heated - it's amazing that oil can flow all that distance without cooling to ambient temperatures.
It's my understanding that friction from viscous drag is the designed heat source.
It's weird to hear the author talk with the sense that "I hope Shale Oil can be ramped up in order to stave off recession" when the environmental (CO2 and water) costs are so horrendous for these technologies. I know which I prefer and it ain't money.
Good point. I wonder where they get the water from, and how they dispose of the waste water to multiply frac 30,000 wells in the Bakken by 2020. Seems like a big stretch.
I read over your blog you have some very interesting points. However,in regards to your first question (Is this really a new drilling technique?)you cite your source as wikipedia. Does this mean you trust wikipedia as a realiable source? I surely hope not, because as you know anyone in their right ( or wrong) mind can post whatever they feel is "fact" on there.
Also, you make a claim that if additional U.S. oil is produced than U.S. imports will increase as well which may "help keep the US out of recession," I would have to assume you mean that you feel the U.S. is not already in a deep recession, if not depression.