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Tech Talk - an explanation of the coming series
Posted by Heading Out on April 24, 2011 - 4:50am
One of the problems in trying to project future demand and supply of oil and other fossil fuels is that the decisions on their availability and use are often controlled by factors other than their geological availability. Yet, at the same time, fuels cannot be created out of thin air (or empty rock) nor can viable technologies be created similarly, purely by having the prevailing governing bodies pass the appropriate legislation (see, for example, cellulosic ethanol production). If fossil fuels are to be brought to market in a timely manner there are certain basic steps that have to have occurred.
The first step is that the deposit of whatever type has to have been found and identified. Thus, when folk discuss the shortfalls inevitably coming in the supply of crude oil, the first indication made usually refers to the decline in the discovery of sufficient new oil in reservoirs to replace that which is being removed. And when the question is raised as to whether we are going to run out of oil and if so, when, the first place to look is toward what resources remain that could be counted as a future reserve for production.
In that definition lies the first of the stumbling blocks that many commentators fail to recognize in writing about the future availability of fuels. It is a point that I made in my discussion of shale gas; namely that while there may be a lot of it out there, at present the volumes commercially producible are, in total, significantly less than the total volume (perhaps as little as 7% ). The total volumes that exist in the various fields are considered the resource (i.e. in this case 862 Tcf of natural gas), while the amount that can be commercially extracted is considered the reserve (in this case 60 Tcf). Confusion over the relevant values in each category, and the conditions under which volumes switch from one category to the other have been part of the debate on the glohal energy future that has, on occasion, bubbled up in places like The Oil Drum.
So if I am to develop a valid picture of where the world future is going in terms of the fossil fuels that will continue, in large measure, to power it over the next 20 years, it is important to look at the underlying resources that are available, and whether or not they can be considered reserves. In many cases that is a relatively easy initial assessment since the volumes in question are already being produced, or are in process of being produced.
But in that process there is another somewhat controversial number, and that is the rate at which production from a field will decline over the time that the fuel is being extracted. Back in 2009 when I wrote the initial tech talk explaining some of the reasons for this decline in an oilfield, the assumed value for this decline rate was on average 4% per annum, yet there are fields which have declined much faster than this. For example, production from the Cantarell field in Mexico fell more than 75% between 2004 and 2010, with decline rates reaching more than 12% per year. Mexico has not been alone in seeing production collapse rates of this level, and yet the impact of declining production from existing fields, and the resulting need to replace it, is a factor that is not fully recognized, yet must be in any rational discussion of future conditions. If, for the sake of example, we accept that global oil production today is 88 mbd, a global decline rate average of 4% in production from existing wells per year, will require that, just to maintain production, an additional 3.52 mbd of new production must be brought on line each year. If, however, the true rate of decline is on average 5%, then this number jumps to 4.4 mbd, and if the true decline is 6%, then it rises to 5.28 mbd.(Bear in mind that this does not include the anticipated increases in demand which still run at around 1.5 mbd).
Now there are countries, such as the Kingdom of Saudi Arabia (KSA), that can manage production and the opening of new developments so that there is sufficient new production in existing fields that decline rates within the field can be kept to perhaps 2%, and new fields brought on line that reverse the total decline. KSA has been relatively forthright in the past in recognizing that without such activity they would have faced declining levels of production of perhaps 800,000 bd of their total of around 9 mbd of production. The problem, of course, is that all fields are finite. Particularly when production has been running for decades, there comes a point where the volumes available have been consumed, and there is nothing left.
Conventionally that has been a steadily changing process. As I noted in that earlier tech talk, vertical wells progressively fall in production. However, in recent years, the production of oil and natural gas is being increasingly supplied from horizontal wells which do not have the same changes in production geometry over time. Rather, the well may continue at relatively stable production levels until the underlying water used to maintain pressure in the formation, rises to the level of the well. And at that point the decline rate becomes very steep indeed.
In passing I should note that this “watering out” of the wells, which happens in oilwell production is not the likely cause of the dramatic fall in natural gas production from shale gas wells that has been documented.
I am reviewing these points about the changes in production with time, to explain why it is very difficult to make more than very broad generalizations when one talks about oil or natural gas (or coal for that matter) production into the future, looking only at the overall numbers. The volumes of fuel that will be available are more accurately assessed from considering the individual countries from which the production is and will be coming, what the potential futures of the fields in those countries are, and the other considerations (such as imminent or ongoing civil war) that might affect field production.
What I intend, therefore, to do next is to start with the major oil producers, as listed in the earlier review, although not always in that order. By looking at the different fields both past, present, and future, in light of existing and possible relatively novel technologies for extraction (such as, for example, burning some of the oil in place so as to help produce the rest) I will try to bring a more accurate assessment of what the future production is likely to be, and thus build up an assessment of global production as the series continues. The top three historic producers have been the United States, Russia and Saudi Arabia, and so the series will start with North America, and more specifically the United States.
But particularly in these times when the stability of some of the producing countries is becoming more questionable, external factors do have to be addressed. Unfortunately many of these changes, being political, are harder to predict. As a result, while I will include the reasons for some of the decisions I use in building this series, I will not go into those in much depth. Rather I will focus more on the likely levels of future production that might be achieved.
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28 Responses to Peak Oil – April 2011 Update
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gailtheactuary says:
April 21, 2011 at 9:21 pm
The problems for the US are basically financial. As long as these can be papered-over, the US should do all right. These are very serious problems, and cannot be fixed at all easily (or maybe “at all, period”). This is why I am much more pessimistic about the US’ long term prospects. QE2 [“quantitative easing #2”] is doing a pretty good job of papering over the problems, but once it goes, we are stuck. [Maybe, would “we are had” also be a good choice of words?]
http://ourfiniteworld.com/2011/04/21/peak-oil-april-2011-update/#more-2379
For those who haven’t seen my story yet I’ll start the economic reality portion of the shale gas play.
Back in ’08 I was on contract to Devon working for the drilling dept handling the E Texas shale gas program. That spring the geology dept requested that the drillers contract ever rig they could…don’t worry about the day rate or contract terms. The need at that time was obvious. Devon was one of the early big players and NG prices had just nudged up to almost $13/mcf. But it wasn’t just the higher NG prices motivating them. Being a public company it was critical to keep the company’s reserve base at least constant y-o-y but really needed an increase to make Wall Street happy and the stock price moving up.
Though the initial wells came on at impressive rates they typically showed decline rates of 60% or more. Thus a well that came on at 4 million cf/d might be doing less than 1 million cf after just two years. As a comparison many conventional reservoirs might not show an initial decline for several years…some times considerably longer. So these were certainly exciting times. But by the end of ’08 NG prices had begun a free fall thanks to demand destruction associated with the financial meltdown. By the end of the year prices were heading below $6/ million cf. Devon still had some “sweet spots” to drill that could sneak a profit out. Even the wells that wouldn’t recover their costs would still add to the reserve base. But the company had reached its limit. Within two months they reduced the number of rigs they were running in E Texas from 18 to 4. And paid a total of $40 million cancellation penalties to let those rigs go.
Devon still has rigs running in various SG plays but the glory days are long going. As a result of over extending themselves Devon had to liquidate some of the most valuable drilling rights anyone owned around the globe: Deep Water Brazil and Gulf of Mexico. Today they are still functioning but are just a shadow of their former selves: once one of the three largest independent companies in the US. Even the hope of increased NG has passed. About 6 months ago the president of Devon pointed out that the continued decline of their SG wells had reached the point that cash flow would remain very low even with new higher prices.
But there are still SG plays that are economic to develop. Just not as many and not as profitable. The Marcellus has an advantage of being close to a high priced market and thus reduced transport costs. The super hot Eagle Ford play in S Texas owes most of its activity thanks to the high oil yield coming from its wells. Given current NG prices in S Texas I suspect at least 80% of these wells wouldn’t be drilling if it were not for the oil yield. The oil/NG in the EF was known for a long time. I completed my first marginal EF well over 30 years ago at the tail end of the late 70’s boom times. High oil prices and much improved technology has made all the difference.
So as HO has pointed out there is a huge difference between “resource” and “reserves” volume estimates. And it will boil down to the price of NG. IMHO I don't think we'll see much more improvement in the technology. While drilling and frac methods have greatly improved I see little potential for much change at this point. Prices have seen some improvement over the last year. Continued improvements will allow more SG completions. But it should be noted that the major players in all the SG are still the public companies that remain focused on reserve base increases as much or more than profits. My company is privately owned and thus has no stock to hype and couldn’t care less how Wall Street might value us. We don’t drill SG wells: they are not as profitable as our deep conventional NG plays. And we are in the game just for the cash flow and profit. But on the downside we don’t have but a small fraction of the number of conventional prospects to drill as the SG players have today.
I'm a little confused by ExxonMobil's change in the focus of their advertisements. The old message was, as shown below, that Peak Oil is decades away. The new message, with an earnest looking geologist on TV, is that shale gas will save the day. What happened?
Some quotes from a few years ago:
EXXONMOBIL:
CERA:
OPEC:
Since the foregoing group, by and large, does not "subscribe to the peak-oil theory," historical peaks like Texas and the North Sea (which accounted for about 9% of cumulative global crude oil production through 2005, and which were developed by private companies, using the best available technology, with virtually no restrictions on drilling) present problems for them, but that's why the Alternative History Theory was proposed, to-wit, the Texas production decline was a result of a Midland, Texas based Communist takeover of Texas oil fields, while the North Sea decline corresponded to a the takeover of North Sea oil fields by a group of radical Vegan terrorists. Problem solved. No conflicts.
Nice chart. I would like it very much if we abolish the term BOE (barrel of oil equivalent) for three reasons. Gas is not oil and you can't make jet fuel or diesel or gasoline from it. Gas reserves do not meaningfully "replace" oil reserves. BOE on a small cap PowerPoint is a ruse to fleece investors.
Brent, WTI, LL, and SLCO are what matter.
Of course, technically you can make liquid transportation fuels from natural gas, using the GTL process, but it is hugely capital intensive and consumes a good deal of the energy content of the gas in the process. It's probably more efficient to transport the gas as LNG and to use it as a ground transportation fuel in the form of CNG or LNG. Having said that, there is that pesky problem of gradually shifting our ground transportation reliance from one form of fossil fuel to another form of fossil fuel.
We make methanol from natural gas today at like a 1.25 a gallon. It has half the energy of gasoline but still. I think it is GThydrocarbons that is hugely capital intensive. Of course there's nothing wrong with CNG ground transportation either.
Coal-fired aircraft. CNG bulldozers, Bradleys, Abrams. Convert 300,000 Freightliners and Peterbilts. Scrap 120,000 gas stations and 30,000 miles of pipe. Piece of cake.
CNG Bulldozers? Scrap gas stations? Won't happen. These will: biofuels trump food for the poor, and coal to liquids, either conventional or from in situ coal seam gasification. Both viable now, with +$100 oil, and neither of them require either scrapping the entire distribution infrastructure or building a different one.
Just have to dig out the old blueprints;
http://www.tractordata.com/farm-tractors/000/0/5/52-john-deere-730-engin...
Scroll down to the LP gas version. Shouldn't be hard to convert that to CNG. A 360 CI (5.9L) two cylinder. 1125 RPM at full throttle.
I know, we could do a lot better with modern technology.
I've driven those old two-cylinder John Deeres. They were incredible. Two great big cylinders, each about 180 cubic inches (3 litres), for a total of 360 CI (6 L). I loved the distinctive POCKETA-POCKETA-POCKETA sound.
I've seen the LP versions of them. They were moderately popular at one time when you get LP for next to nothing. I've heard they can be converted to CNG with about half a day's work. But there aren't many of them around.
"The old message was, as shown below, that Peak Oil is decades away. The new message, with an earnest looking geologist on TV, is that shale gas will save the day. What happened?"
Marketing was defeated my Mathematics. Admittedly, that doesn't happen often. But having to explain missed production numbers year after year eventually takes it's toll.
It would be interesting to subtract out natural gas as BOE in ExxonMobil's annual reports, and look at how many actual barrels of proven reserves of crude oil that they have added since 2005, versus what they have produced.
Found some numbers:
http://viableopposition.blogspot.com/2011/02/if-exxon-cant-find-oil-who-...
If Exxon can't find oil, who can?
*Apparently inclusive of acquisitions, which would not be a net addition to proven reserves globally
"Liquids" is another ruse. The issue is light sweet crude, not condensate.
Those figures look like quite a worry. On the other hand, I have just one problem with the interpretation. That's because of my knowledge about the Australian mining industry. What happens here is that a lot of the mineral discoveries are made by small exploration companies, who are ultimately taken over by one of the big boys. Looking at the figures for Reserves - Production + Discovery for one of the large miners, and excluding reserves acquired through purchase, would therefore provide a misleading picture of the industry.
Is the oil industry like this, too? Are many of the discoveries made by smaller operators who are then taken over by larger companies with the resources to develop the project?
Abby - Not such much on an individual discovery basis but at the corporate level. Especially true when we have a bust like we did back in late '08. Companies, particularly public ones, become especially vulnerable at such times. For the biggest companies, like ExxonMobil, they can increase their reserve base more easily though acqusitions than drilling.
Rockman:
I am always glad to hear your explanation of oil and gas development, with your first hand knowledge being very useful in these discussions on energy.
The situation of economics of oil and gas production described by HO and Rockman has application in the Bakken formation. Biggest Bakken developer is Continental Resources of Enid, OK. Harold Hamm, their CEO, stated in 2008 that the break even point was $50 per barrel, though that is probably higher now with steel prices and transport costs rising 10 to 20% per year.
The decline rate of Bakken wells is like the shale gas wells, with 50% per year being common and some having 90% decline in one year. This rapid decline means that oil prices have to stay high in order for producers to continually drill more wells just to maintain constant production. Should the oil price drop down to $50/barrel for any extended period of time, maybe two or three years, then the oil production coming from the Bakken would drop by 1/3 or 1/2 in a very short time as drilling/fracking ceased.
Looking forward to the series. I have definite approaches to best reason about future production, but it doesn't rely on a bottom-up analysis. The issue is that if you only know about something through the data you have, it then precludes one from doing any kind of inferencing. This always holds unless you have some sort of model providing a foundation for inferring some future behavior (except for the default of linear extrapolation).
So that describes the eventual limitations of a model-free bottoms-up approach, as it is impossible to do a correct future extrapolation. This happens in every field of study and depletion analysis is no different.
As yourselves I have recently noticed the Exxon Mobile commercials airing quite frequently.I only paid half attention to em but do remember hearing the spokesman saying NG will run us for the next 100 years.
I'm so relieved now to know we have NG for the next 100 years which will allow us the time for a switch over in energies.he he
How much do we really have? What say you on an estimate,Thanks.
Tim - My story won't change: how much NG will we produce in the future? Easy to answer: at $3/mcf...not a whole lot. At $15/mcf a whole lot. Wait...were you looking for some numbers? I could make a real scientific looking model that might seem really valid. But in reality I would just make a guess and then fake the model to fit my numbers.
Sorry...just came off 3 long days on a drill rig and just don't have the energy to blow smoke up your butt. LOL. Given I'm not working fo a pubic company with stock to hype there's no reason to tell folks fairy tales.
Official story 862 tcf recoverable in US. In reality only 1/8 of that, mostly offshore.
The gratuitous knock on cellulosic ethanol is ridiculously myopic.
Sustainably harvested cellulose from crop waste, wood, etc. could produce 80 billion gallons of ethanol.
http://www.poet.com/discovery/message_from_our_ceo.asp
I heard a story on NPR last Wednesday or Thursday about a power plant that is making methanol or ethanol from wood chips to supplement their gas fired power plant. They chose to take the free wood waste and convert it into a usable fuel for the power plant. The power company did not burn the wood chips directly because of emissions and the soot would clog the boiler tubes. The company is in Sweden or Denmark and they are doing it to reduce GHG, but I don't know the cost.
The NPR story appears to prove cellulostic ethanol is possible, but is it economical against cheap nat. gas? Maybe its soon economical compared to oil at $200/barrel.
I guess you are talking about the bio fuel project at Södra Cell, Värö, on the swedish west coast.
http://www.sodra.com/en/Media--news/News/News-about-Sodra-Cell/Sodra-Cel...
I worked there during a maintainance stop the spring 2007. Best money I ever made.
Something just sounds wrong about that Sodra plant. I grew up near (and worked several years in) an 850 TPD sulphate pulp mill. They heavily re-used all waste product for energy, including lignin, sawdust and bark, but wern't anywhere near net neutral on energy. Of course at that plant, all de-barking and chipping was done in the plant as part of the process, and a lot of the output was fine papers rather than raw pulp. Here's what I'd guess that Sodra plant is doing to reduce the plant's external energy use. 1) all de-barking and chipping in the forest as part of the logging operation using diesel fuel, eliminates the energy cost of the 5 x 250 kw de-barking drums and the 475 kw chipper, plus conveyors and water pumping. 2) re-directing a lot of the logging output to external energy-unaccounted lumber mills, then collecting the waste from the lumber mills for use at the pulp mill. 3) only bare-minimum processing of the pulp, i.e. no refining or bleaching operations, compare to our plant's long lines of 300 kw refiner screens. Not doing any of the further processing operations required to make fine paper or even decent rough envelope. 4) selectively avoiding any use of hardwoods which are much more difficult to process and provide much less lignins for energy. Results in having to slash-and-scrap hardwoods out of the forest, else the desireable softwoods won't be able to re-grow. 5) Not accounting for any of the diesel fuels used in the logging, transport and re-forestration operations.
Or, they might even be a simple unbleached groundwood pulp mill, specializing in rough newsprint pulp. But then, who uses newsprint anymore?
I do not have those details about the plant at Värö. But I know the following; They use almost exclusivly spruce, since this is the main industrial timber source in Sweden. And as we all know, spruce is in the soft end of the timber hardness scale.
Secondly; they do not only produce paper mass (is that what you call "pulp"?) but also paper. Once when I got lost at the plant (it is easy to get lost at a large processing plant of any kind) I found myself in the paper making part of the plant. They have some impressing machines there. I could think of no other use for it than as a paper making device.
Myself I made most of my work at the boilers, I never had reason to go near the paper section.
80bgal with an EROEI of 0.8 doesn't help much.
Hello everyone,
I'm new here and this is my first post. Ensligh is not my native language so please excuse my grammer mistakes. I'm interested in peak oil about 3 years and i read a few books, many articles and study many statistics. I also made some production models, not based on mathematics but on mixture of forecasts, BP statistics and my own predictions. I know that is not correct scientific procedure so I decide to write this comment. I really like math models made by webhubbletelescope and i really like rockman's post about drilling oil wells. Also I appreciate work of Heading out and many other people publishing on TOD. I find the idea of making one big world producion model very interesting and ambcious. But now to the merit of my post. I read this comment from Rockman:
"Jerry – A nice analysis IMHO. But it might be a surprise that I think you’re still being a tad optimistic. Let’s start with a simple but fairly representative model of oil production. Water drive is the primary reservoir energy. And the vast majority of such reservoirs have a similar decline profile. I’m going to cut to the bottom line quickly: it takes a much longer time to recover the second half of the reserves that the first 50%. It’s true that horizontal wells can cut the recovery time for the last 50% but it will still take much longer. More importantly, the vast majority of such reservoir are not viable for such acceleration. The examples where they work can be very dramatic. But only for a small percentage of the fields.!
"So back to the basics of PO: it’s all about rate…not future recovery. I doubt that we have 50% URR left to produce. But even if we do it will take a great deal longer…maybe as much as 10 times as long…to recover that last half. Consider the current status of the US: we are the 3rd largest producer of oil on the planet. But it’s coming out of the ground at the rate of 10 bopd per well. Consider that typically these wells initially came on at 100’s of bopd. IOW our last “50%” of our recover is producing at around 1/10 (or slower) than the first 50%. So if it took 60 – 70 years for the first half then it will take 500+ years for the second half? That’s probably not a very good numerical model but it does give some sense that the last 50% (if it will actually ever be produced) may not be much of a game changer."
That is very important iformation if is it true. We should base or models on geological presumptions, not only on mathematics. As I mentioned upper, I made some models of my own a when i look ond this older model based on 3 scenarios of production declain by 2%, 3% and 4% per year, that make very incorrect predictions. If you make one big mathematic model based on Hubbert theory you get nice model, but in long time scale. So if we can built this rockman's idea into the model we could get very precise model. I presume we know the number of existing wells in each country so if we substitute production of each well by 10 bopd we can get the stable world production after peak oil. I know that each country has specific geological conditions so it's up to us to make right predictions. I know it isn't easy task but we could at least try it. We should also make predictions of future production of each country at some price level. For example, Canada could supply market by 3mbpd in year 2020 at 120 dolars of today money. Please don't nail me up, it's only an example. I also noticed in rockman's post that if the investment in drilling technology is made, we could drill that 10 bopd per well at same price level. If I understand it in wrong way, my apologies. In that case if it is right presumption we could say, that price of oil about thousands of dolars per barrel is rule out because the drill price will be approximately constant but what is changing is demand. And when oil price will be to high people just don't buy it cause they can't afford it. So that is my comment. I´m looking for responses, especially for critical one and one more time, I apology for my poor english.
herb - Your English is fine. The first problem you'll have is a lack of data. With the exception of the US and just a few countries you won't find the details you need. This is especially true of the Saudi govt. They consider this info a state secret and seriously protect it.
Beyond that problem the reservoir dynamics vary greatly between different fields. Compare Ghawar Field to Mexico's Cantrell Field. Ghawar is a water drive reservoir with a lot of water being injected down dip of the producers to help recover. Cantrell is a pressure depletion drive with nitrogen injected into the top of the reservoir in order to maintain pressure and increase recovery. At one point in time the decline rate (DR) at Cantrell may be close to zero with Ghawar's DR around 4%. But in less than a year the N2 gas cap at Cantrell reaches the producing wells and the DR could jump to 20%. And then the Saudis could drill a lot of horizontal wells in Ghawar and greatly reduce its DR. But some years later the water level begins to reach the horizontal wells and those wells suffer a DR of 40% or more.
Now imagine trying to normalize production from a thousand other fields to account for the different reservoir dynamics. And trying to do so with little or no detailed info for most of those fields.
Drilling 10 bopd wells thanks to new technology? Only rarely would this work and then only at high prices. Perhaps you're confusing drilling with producing such a well. Many wells making 10 bopd at current prices are making a very nice profit because the cost to produce such a well is a relative small portion of the cash flow. The cost of drilling such a well is a very different matter. I'm currently in the process of proposing a drilling program in some very old fields currently averaging less than 10 bopd per well. I would drill horizontal wells at a cost of $2 million each. And certainly not for a 10 bopd. Hopefully the wells would come on at 200 bopd. How much oil (and thus the profitability) are difficult to model with much credibility. The plan is to do 3 (6 wells total) pilot projects and then produce for 6 months. At that time the data will hopefully support the drilling of 100+ more wells.
And now for my very crude thoughts on "modeling". Modeling is a lot like masturbation: it's OK as long as you don't start believing it's the real thing. LOL. Modeling is fine so don't give up the hunt. But as a wise man once said: production data beats theory (models) every time.
Thank for your respond, I really appreciate it. I know the problem about data lack, but i have seen few articles here about KSA wells and drilling so I thouht that won't be such problem. I know about different injection metods so I'd like to ask, what technologies are used in states like Iran, Iraq, Nigeria, Angola or in former Soviet Union states. Are they using modern drilling metods including horizontal wells or they are waiting for better prices of oil? I'm interested because I live in Europe and we are to much dependent on those countries, except Venezuela of course. World oil production model is maybe useless, but for planning energetic strategy for my region it's very important. For example Russia, how long can they keep their production level and how big will be decline rate? And can they improve they drilling technology? I read once they produce as much as they can cause in permanent frozen land they must.
The modeling as you said is often useless and I admit your mention. This is the reason why I wrote the first post because the measure of uncertainty is big. I really like the math but i see that often gives a wrong predictions. I would like to know you opinion about world production of crude oil, all liquids, natural gas, coal, their peak years, lenght of platau and resulting decline rate. My prior study is electroenergetic and that infromation would be very useful cause you must make investments into the energetic sector many years in advance. The consupmtion of my country is not to big, only about 210 tbpd and space to energy saves is big but we are running out of coal in next 40 years and that would be very big problem.
herb - As far as the KSA goes we can't even confirm how much oil the country has produced on a given day let alone from a single field or well. Last I heard it was still high treason for any Saudi national to release such info.
Injection methods: doesn't vary by country. It's completely dependent of the reservoir dynamics. Water injection will destroy a pressure depletion field. N2 injection into a water drive reservoir is almost always a money losing proposition. Even water injection into a water drive reservoir can be a money losing effort in some fields...the water bypasses the oil and goes straight to the producing wells and kills their oil production. Horizontal drilling is big all around the globe. It's being employed where the economics and reserve dynamics allow. But each application is different. There are fields that benefit from hz wells at $40/bbl while many others lose money if oil is less than $80/bbl.
I would never call models useless per se. I do think their real value is highlighting what factors impact the models and, hopefully, the reality of oil production. But predictions should always be suspect since they tend to depend heavily on the assumptions used to generate the model. The design of the model may be perfect but if faulty assumptions are used then one may well end up with a useless product. Again consider Saudi production. Such great assumptions have to be made to build such a model that the result could be badly flawed given how wrong the assumptions could be.
Russia: in past decades I've heard Russian production technology was very poor. But I suspect it's much improved but still perhaps a bit inefficient.
Predicting PO dates, etc? I wouldn't touch that with a 10' pole...and I don't mean someone from Poland. LOL. But I'm a very big proponent of peak plateau with many small PO's along the way. I don't believe we're heading for a cliff. After 36 years in the oil patch I've learned that the larger the system you're dealing with the slower it can change. The analogy is a very large ship: it can change course only very slowly. But once that course is set it would take a huge force to alter its path. I feel the same about global oil production. But only from the natural aspects. Political/military/demand destruction aspects can produce much more rapid change than Mother Earth. And modeling those aspects with any certain is truly impossible IMHO.
Don't take my words as pessimistic...stick with your modeling efforts. But I think the important info you'll gain is how the different factors play against each other and not some great confidence in predicting specific outcomes.
ROCK:Predicting PO dates, etc? I wouldn't touch that with a 10' pole...and I don't mean someone from Poland I was wondering if herbage was from Poland myself--thought they had a bit more than 40 years coal left though, so I checked it out and found the Czech Republic used 207,000 bpd in 2007, Romania used 238,000 bpd in 2006 and also produces coal for power generation.
herbage: Sorry shouldn't be talking around you like that herbage--did I guess right?--I used to listen to a Prague webcast all the time--it played some of the best Chicago to Mississippi Delta old blues I could find for free till it switched to swing and jazz.
Back to ROCK: Sounds like you had a lovely time in Baton Rouge, hope the drive was pretty anyway. That big snow pile next my house is down to about half what was in the picture...snow melt works almost the inverse of oil reserves, the more that is gone, the faster it goes..of course it depends on the weather ?- )
Looking forward to comments from both of you in the rest of this series.
And after that brief musical interlude (subliminal: WFMU) back to the topic.
I wouldn't be applying the specific math I advocate if the data was less variable. There is a great variation in sizes and extraction profiles because of natural disorder and the way that maximum entropy plays out. As far as I am concerned the more disorder, the better.
As an example, atmospheric gases are completely randomized yet the atmospheric pressure decreases with altitude in a precise way, and in complete agreement with maximum entropy theory. This works out the same way for lots of other physical phenomena and the randomized supply of oil should be no different.
The field is sparsely populated, so always room for more problem solvers.
As an example, atmospheric gases are completely randomized yet the atmospheric pressure decreases with altitude in a precise way, and in complete agreement with maximum entropy theory.
But regardless how good the model enter the wrong gas quantity, wrong planet size or planet density and the resultant atmospheric pressures can be worlds off from the reality the model is attempting to define--I guess we really are all just material girls living in this empirical world.
You must really love disorder if you've left WFMU on for more than a second or two by the way...?- )
You can potentially estimate it from two pairs of points, which is what maximum entropy says -- that you can make darn good estimates with minimal info.
BTW, WFMU harnesses entropy.
Would each of those two pairs would have to have one high altitude pressure and one low altitude pressure? Or am I swimming in the wrong sea of ether?
I only had WFMU on for a few seconds...whatever they were doing I wasn't going to subject myself to it any longer, or I might have come down with the blues...which is something I'd far rather listen to than have ?- )
Better yet, you would only need one pair (altitude,pressure) if they told you it was the average.
WFMU depends on the few seconds you tune it in.
That is very little data. If I understand you correctly the pair would be giving you the altitude at which the pressure was equal to the average pressure of the entire system, which seems a fair amount of information to actually have, but then maybe not so much since you should be able to come up with that system average pressure by only having pressure at two different altitudes, I think. Or can the one pair needed be any altitude and the average pressure for that altitude...which is quite a bit less information and doesn't seem like enough to my poor brain, as I believe in this type of pressure modelling we would be talking average pressure at every altitude in our calculations.
That is the Maximum Entropy Principle in a nutshell. Given only a knowledge of some average value, the least biased estimate follows maximizing entropy subject to that constraint. It may seem unlikely yet it describes the way that nature works, in particular when things have been allowed to mix rather randomly.
Your using the atmospheric pressure example helped me get a spatial visualization of the possibility of the calculation process. There is a beauty to simplicity of it--but my math skills are much atrophied or are they just a victim of all consuming entropy ?- ) They won't be allowing me to follow along on the really fun part of the ride.
Entropy, wish I had a slightly better handle on the term, all its definitions seem interrelated but in information theory, a measure of the information content of a message evaluated as to its uncertainty
and a thermodynamic measure of the amount of energy available for doing work in a system undergoing change and then a measure of the degree of disorder in a substance or a system: entropy always increases and the available energy diminishes in a closed system, such as the universe and finally the definition with which I was most familiar with before I joined these boards a process of degeneration marked variously by increasing degrees of uncertainty, disorder, fragmentation, chaos, etc.; specif., such a process regarded as the inevitable, terminal stage in the life of a social system of structure are certainly not all one and the same--though the last three and especially the last two are very, very close.
I really do get thrown by the word. Of course when you add in this final definition COMMUNICATION measure of efficiency: a measure of the random errors noise occurring in the transmission of signals, and from this a measure of the efficiency of transmission systems you start to wonder if understanding what entropy really is is by its very nature a hopeless task ?- ) I am being a bit facetious now, but you can see how a poor lubber can feel really lost at sea when the word entropy is floating all around.
The connection between the information theory definition of entropy and the thermodynamic definition is more mathematical and descriptive than anything else.
It is a quirk of nature that the two are related, which makes it confusing when you first come across it. Yet, once you understand the connection, lots of things start making sense.
One guy that is trying to make sense of the connection between the two is John Carlos Baez, who runs the http://AzimuthProject.com blog. That is pure mathematics but his perspective is trying to understand Resource limitations, Global Warming, etc., same as here.
in that first definition it should have said 'unavailable' instead of 'available', sorry.
The concept of entropy is a bit hard for me wrap around. Entropy always increases as energy decreases in a closed system, such as the universe, but when all the energy is drained matter would form perfect crystals, no information would be hidden and there would be no entropy. That seems like at least a paradox if not an outright contradiction.
The section on entropy was the only part of Susskind's book "The Black Hole War" that was not perfectly clear to me.
It would not form perfect crystals as that would imply predictability, which is the opposite direction of entropy increasing.
Schoolbook entropy is taught from the point of view of the gearhead and greasemonkey who only wants to know about the end-result of Carnot efficiency on engines. This confuses everyone later on when we try to apply it to 95% of its other practical applications. The Oil Conundrum describes several of those without getting into any paradoxes. The only possible paradox I see is that the solutions to problems actually get easier the more entropic they become. This image from the book shows my classification of entropy:
It is not a paradox to me, as the solutions only get easier because one can apply the Maximum Entropy Principle.
It would not form perfect crystals as that would imply predictability, which is the opposite direction of entropy increasing
Well I'd think calling Leonard Susskind a greasemonkey or a gearhead is a bit harsh. In a America just because someone is the son of a Bronx plumber doesn't condemn them to the same class--last I heard ?- )
from page 140 of the paperback version of 'The Black Hole Wars'
Now Leonard may be oversimplifying above for gearhead readers.
He deals with the uncertainty earlier when defining zero point motion or what Brian Greene has labelled quantum jitters. But he leaves you hanging there a bit. In this case he described a non reactive a one centimeter cube vessel at absolute zero, where all the atoms within would supposedly come to rest on the sides except they don't because of uncertainty and they still exert pressure on the sides of the one cubic centimeter vessel.
[from page 97 of the same book]
That certainly seems at odds with the zero entropy statement and the two left me scratching my head. Though what happens if you shrink that vessel to a planck length cube-which of course contains only one bit of information-at absolute zero? It would seem the uncertainty principle would have that bit alternating between existence and non existence, at least to a poor lubber like me.
Now that seems to conflict with the first law of thermodynamics. It just seems what is really being described here is the flip side of the description of the big bang where no calculations can be made until the smallest discrete time unit, planck time, has elaspsed. These two 'edges' seem to me the limit of our mathematical model of the universe--which the same math appears to describe as holographic--making the entire universe something like an inside out black hole. Or in other words no one has a clue what this all REALLY is.
But that is all out there at the edges, the place we try and take our thought process, it has little or no effect on the matter at hand which Maximum Entropy Principle seems to describe so well.
The key to dealing with quantum effects is to know when they do or don't apply at the macroscopic level.
At the top, I was placing thermodynamics in the context of mechanical engineering applications (i.e. gearheads) where the main goal is to extract work and exchange heat. Most people think of entropy only in those terms but a lot of other contexts where it is very useful.
No doubt, I really did appreciate your using the atmospheric pressure example to demostrate how the Maximum Entropy Principle works. I have had a fair feeling of what you were going about, but that context made simplicity of the concept jump out a me. Thanks.
In a related matter, I just happened to skim by the McLaughlin Group a little earlier. Pat Buchanan was carefully tiptoeing around actually saying 'Peak Oil' while at the same time saying many of the oil companies and fields where at or past their production peaks, and that there was probably no going back to $3/gal gasoline. I used to watch that show regularly through the Bush years and rarely if ever heard any thing approaching the term 'Peak Oil' used then.
I skipped on an shut the sreen down as Zuckerman started to launch into a tirade on not letting folks go after energy sources in the US, but from Buchanan's expression I've a feeling he may get it.
To Luke H: Yes, I'm from Czech republic.
To WHT: I must make clear that I can't make valuable models. It's not based on mathematic methods but on fortunetellery. I just made prediction based on BP statical review so I made graphs from 1965 to 2030 for each country a and make data extrapolation to fit the bell-shaped curve. Then I made sum of that graphs for each region and then for whole world. For some countries like Norwegian or Great Britain it works well but for Iran, Iraq or KSA it is only my poor guess. My ambition wasn't make precise model. I wanted to make orientational model. As Rockman said he's a proponent of long plateau scenario so I'm too. It's pretty big dynamic system and there we can expect very slow changes in time scale. Of course we don't know if some country will make stop their productions for politician reasons but that should not be part of our prediction models. I must quote Rockman one more when he said that production data always beat models. I agree. But what we can really do is this. We can make prediction for each country a discuss about how it is propable or relevant. We should do this for midterm horizont, let say to year 2030. After few years we'll see how we were wrong and we could make correction. The biggest problem would be we don´t know precise data and second one, the mentioned political decisions so we can't decide what is responsible for sudden decline of production. On that base we could also make quite good estimates about size of oil reserves each country and compare it with numbers they report to public.
The agggregate of country data beats the sum of models for individual countries. That is just the law of large numbers and the central limit theorem in action.
If you can do both it is even better. For example: Consider the correct interpretation of the classic logistic Hubbert curve. It isn't a single rate that applies to depleting a geological volume but a dispersion of rates amongst several operating regions that aggregate to model the curve.
If we segregate the rates into intervals the curves look like the following, with the aggregate in this case following the derivative of the logistic sigmoid:
This is essentially the way that discoveries accumulate, with the most technologically advanced regions (such as the USA) exploiting the dispersed regions first, and then the slower regions following.
So you see the power of a model that both gets the subregions correct and gets the global situation correct. It is a most amazing result!