In 1956, M. King Hubbert predicted that crude oil production in the U.S. (ex-Alaska) would peak in rate around 1970, to be followed by a long, irreversible decline. Hubbert nailed the timing of the peak, and in doing so, cemented his status as a technological visionary among neo-Malthusians and opponents of fossil fuels.
The method Hubbert employed to make his prediction is simple and elegant, almost trivial in its application. But is it valid? Should we base policy decisions on its conclusions?
Before answering that question, consider that Hubbert’s 1956 paper[1] contained a similar prediction: that Lower 48 natural gas production would peak in the early 1970s. In a classic case of confirmation bias, Hubbert’s 1978 update[2] declared his gas prediction correct (as with oil, he had missed the rate prediction on the low side). For Hubbert, gas had begun its “inexorable decline” right on schedule.
In 1956, Hubbert’s estimate of the amount of natural gas that would ultimately be consumed in the U.S. was 850 trillion cubic feet (TCF).
In the 1978 update, Hubbert increased his estimate to 1,103 TCF, but considered that value to be on the high side.
By the end of 2010, we had produced and marketed 1,131 TCF from the Lower 48, more gas than Hubbert thought would ever be possible (Figure 1). We are in the midst of a natural gas boom, with gas production now exceeding the peaks of 1973: rates are over three times higher than the 7 TCF per year Hubbert foresaw for 2010 (Figure 2). The Lower 48 resource base is some 3,100 TCF, three to four times Hubbert’s earlier estimates.[3]
Peak Oilers rarely mention Peak Gas. Hubbert expected his method to work for all resources; why did it fail with respect to gas? The answers to that question shed light on the shortcomings of Peak Oil Theory, and reveal the reasons why it should not be used as a policy-making tool.
Fig. 1: Lower 48 Ultimate Gas Resource Estimates, 1956-2010. MKH = M. King Hubbert. PGC = Potential Gas Committee.
Fig. 2: Hubbert's 1956 & 1978 Estimates vs. Actual Production
Shortcoming #1: Hubbert’s technique depends entirely upon the estimate of the ultimate resource base. Any extrapolation of historical trends contains only the information embedded in the history. There is no way to anticipate “game-changing” developments outside the confines of the history upon which it is based. A forecast of a limited future thus becomes a self-fulfilling prophecy if it is used to set policy.
Shortcoming #2: “Hubbert’s Peak” is the ultimate ceteris paribus analysis. Problem is, all other things are never equal, particularly in the realm of economics. Hubbert’s equations worked well in his experience, so well that he accepted them as immutable laws. Hubbert showed little concern for how changing policies or economics might affect his resource estimates (see Shortcoming #1).
Shortcoming #3: We are all limited by our imaginations. Hubbert could not imagine economic production of hydrocarbons from water depths over 600 feet; we now have production in nearly 10,000 feet of water. Shale rocks were never considered to have economic potential. Moore’s Law has enabled accomplishments in drilling and exploration beyond Hubbert’s wildest dreams.
Hubbert’s Estimate of Ultimate Resources – 1956
At the time of his 1956 paper, Hubbert was a geologic advisor to Shell Development Company in Houston. His estimate of ultimate natural gas for the Lower 48 was derived from his crude oil estimate; at the time gas was regarded a by-product of oil, a nuisance as much as a resource.
Because crude oil and natural gas are genetically related, probably the most reliable procedure for estimating the ultimate reserves of natural gas is from the ratio of gas to crude oil in current production and in the proved reserves. … [Adding the figures so derived to] the cumulative production of 130 trillion cubic feet then gives as the ultimate potential gas reserve of the United States a low figure of 540 or a high of 860 trillion cubic feet. Of these figures the latter seems more reliable …[1]
The latter figure was also in rough agreement with the estimate derived independently by the legendary Wallace E. Pratt, chief geologist for Humble Oil and Refining (a predecessor of ExxonMobil): 850 TCF. Hubbert credited Pratt in Figure 22 of his paper (reproduced as Figure 3 herein), which forecast a peak rate of 14 TCF per year in the early 1970s.
Fig. 3: Hubbert's "Area Under the Curve" Analysis for Lower 48 Gas, 1956.
Hubbert’s Estimate of Ultimate Resources – 1978
In 1978, Hubbert was recently retired as a research geophysicist for the U.S. Geological Survey. Upon looking back at his original work, he concluded:
From these data, it now appears, as of 1978, that the production rates of oil and natural gas in the lower 48 states reached their culminations in the years 1970 and 1973, respectively, and are now in their inexorable decline. [2] [Emphasis added.]
In the 1978 paper, Hubbert introduced new graphical techniques, basing his 1,103 TCF resource estimate on a declining trend of new reserves per foot drilled. He also went to considerable lengths to discredit more optimistic resource estimates from the U.S. Geologic Survey, the Potential Gas Committee and others. Those estimates took a more statistical approach than Hubbert by attempting to quantify the remaining gas in all of the unexplored and undrilled basins. In retrospect, those estimates are more in line with today’s resource estimates.
At the time, Hubbert was not alone in his pessimism for future gas supplies. The nation experienced gas shortages during two extremely cold winters when demand exceeded gas deliverability. Proved reserves were at historic lows. An alarmed Congress passed the Industrial Fuel Use Act (1978), which outlawed new gas-fired electrical generating plants, just one example of a bad policy that was based on a pessimistic resource outlook.
Problems with Estimating EUR
The press and policy makers often portray resource estimation in a deterministic light, as in “We know that umpteen TCF of gas reserves lie off the east coast of the United States.” We know nothing of the sort. It would be more accurate to say “Our mean estimate of the gas resource which may lie off the east coast is umpteen TCF,” but the nuance is lost on folks who struggle with elementary math.
There are two ways to make an estimate of ultimate recovery on a global or national scale. One is to extrapolate historical performance trends using the performance of existing production and discovery trends. This was Hubbert’s technique. The problem with such an approach is that it cannot anticipate a “game-changing” innovation or fundamental shift in economics. The forecast implicitly extends the rules that shaped history, even when those rules no longer apply.
The other approach is a “volumetric” exercise, one in which there is a broad range of uncertainty. The resource estimates of the Potential Gas Committee are an example. The PGC attempts to catalog the “undiscovered, technically recoverable resource” by considering the volume of the known sedimentary basins, the volume of potential reservoir rock, and their likelihood of containing hydrocarbons. Even under this approach the resource estimate has grown over time, as wells are drilled and the production curve, technology and information frontiers advance (Figure 4).
Fig. 4: PGC Estimates of U.S. Ultimate Gas, 1990-2010
Hubbert’s curve was inherently backward-looking. He had no way to look in a crystal ball and divine the “correct” value of the resource estimate; instead he simply presumed that the future must reflect the past:
“… for a large area, such as the United States or Texas, [a production plot] most likely will be a single-cycle curve with only one principal maximum.” [2]
The natural gas case history proves that to be a false presumption. The number of methane molecules that exist in the earth’s crust may be a “fixed, finite” number, but the proportion of those that will ultimately be discovered, produced and marketed as natural gas depends on the interplay of external factors which Hubbert simply ignored: product price, public policy, and technology.
Product Price
Until the mid-1970s, natural gas was dirt cheap, so cheap that drillers rarely targeted it intentionally.[4] Most of the gas that was found and produced was incidental to oil operations, which explains why Hubbert deemed the gas resource to be a ratio of his crude oil estimate.
Figure 5 shows the history of natural gas prices (which was historically priced per mcf, or 1,000 standard cubic feet). The average wellhead price (i.e., the price received by the producer in the field) from 1925 until 1970 was less than 10¢ per mcf (about 66¢ in 2005 dollars). The energy content of one barrel of oil is roughly the same as 6 mcf of gas, so that the cost of buying one barrel’s worth of energy in natural gas form was only 60¢ (or less than $4.00 in 2005 dollars).
Fig. 5: Nominal and Real U.S. Wellhead Gas Prices, 1925-2010
Public Policy
Since 1938, the Natural Gas Act had enforced low gas prices and near monopoly status for the big interstate gas pipelines. It was not unusual for a producer to be locked into a long term gas sales contract at 3¢ per mcf, with no recourse and no alternatives. Intrastate gas (gas that was consumed in the state where it was produced), being free from Federal controls, provided better markets to the producer, and better availability of gas to producing-state consumers.
In an effort to build domestic gas supplies, President Carter signed the Natural Gas Policy Act (NGPA) in 1978. It maintained existing price controls while granting preference to newly-found supplies. Its recognition of a dozen or more “vintages” of gas led to a price structure that became increasingly byzantine over time.
President Reagan began phasing out price controls on oil and gas in 1983. Tax reform ended limited partnerships’ tax shelters for drilling dry holes. The industry floundered as prices tanked and investors vanished. From 1981 until 1985, the count of active drilling rigs declined from 4,500 to 700. Under severe economic pressure, the energy industry consolidated and contracted, then set about figuring out how to regain profitability.
The interstate pipelines were also decontrolled in the mid 1980s. They lost their monopoly status, becoming common carriers more like the railroads. Producers were free for the first time to seek out the most profitable marketing alternatives. Commodities trading began on the NYMEX, with a common exchange point being established at Louisiana’s Henry Hub, a key pipeline interconnect.
Technology
Coincidentally, by about 1985, the impact of cheaper, distributed computing began to be felt in the industry. Directly or indirectly, the PC era would contribute to a number of important technical advances in exploration and well operations, including 3-D seismic, horizontal drilling and logging-while-drilling. Using these and other new technologies, operators began finding ways to produce natural gas from rocks that had been never before been considered to be commercial sources of hydrocarbons. Explorers drilled fewer dry holes, and more efficiently developed smaller accumulations than in earlier days.
It is important to note that the connection between price spikes and technical innovation is often indirect. Many of the important innovations happened during periods of low prices as producers looked for a way to survive hard times by working with the resources at their disposal. And technological advancement tends to be a one-way street: good ideas are not forgotten, and any successful technology spawns copycats and imitators.
Fig. 6: Real Wellhead Price and Lower 48 Gas Production, 1925-2010
Looking Outside the Box
It was always known that some shale rock formations contain gas; the problem was getting the gas out in commercial quantities. Industry pioneer George Mitchell’s Mitchell Energy tried for years to find the key in a shale zone called the Barnett near Fort Worth, TX. Eventually they found that the combination of horizontal wells (wells drilled vertically from the surface, then turned horizontal in the target formation) combined with hydraulic fracturing (“fracking”), produced economic results. In time, Mitchell’s Newark East Barnett Shale field became the nation’s #1 producing gas field. [5]
Strong natural gas prices starting in 2004 drove the search for other productive shales. When the technology was applied to other shale trends (notably the Haynesville of northwest Louisiana and the Marcellus of Pennsylvania, both of which typically produce at higher rates than the Barnett), shale gas development became today’s full-fledged boom. Shale plays tend to cover broad areas compared to conventional sandstone and carbonate gas reservoirs, so the impact on the estimate of the resource base is enormous.
The success of the deepwater Gulf of Mexico is another example of the confluence of price, policy and technology in expanding the resource base. In the 1990s, a time of low product prices, favorable government policy in the form of royalty relief encouraged the search into deepwater. 3-D seismic and cheaper computer processing enabled geoscientists to see reservoirs lying beneath a thick layer of salt. Marine engineering and subsea innovations make it possible to drill and produce in water up to 10,000 feet deep. The result is a major source of hydrocarbons that was unimaginable in Hubbert’s day.
Hubbert’s estimate did cover the offshore, but only the “shelf”, out to a water depth of 600 feet. As it turns out, the deepwater Gulf of Mexico is a major new producing province. Obviously, Hubbert, Pratt and their contemporaries would never have assigned a reserve value to shales or coals, the unconventional sources that today comprise 40% or more of our gas market.
Conclusion
“Hubbert was imaginative and innovative… [but he had] no concept of technological change, economics or how new resource plays evolve. It was a very static view of the world.”– Peter Rose, King Hubbert’s boss at the U.S. Geological Survey. [4]
Hubbert knew a world of low gas prices. Active Federal intervention kept prices low, so low that there was little incentive for innovation or aggressive exploration.
Natural gas dutifully followed Hubbert’s Curve up and over the peak, but about 1985 it veered sharply off the trend, never to look back. That’s about the same time that price decontrol became permanent and producers gained access to commodity markets. We should not be surprised to find the roots of the change in free market economics. Gas is subject to the Law of Supply and Demand just like any other commodity. In addition, the concepts by which we gauge remaining supply (“Resources” and “Reserves”) contain economic considerations in their very definitions.
Hubbert may have been correct about the ultimate volume of gas that would have been produced under pre-1970 prices and marketing structures. That price was unrealistically low compared to the energy content of gas. Today’s gas prices are about six times the pre-1970 average (2005 dollars), but gas is still a relative bargain. (Six thousand cubic feet of gas costs about $24, but can do as much work as one $100 barrel of oil – see Figure 5.)
So, if all this is true, why does Hubbert’s curve seem to work so well for crude oil?
One key fact distinguishes natural gas and oil. Oil can be readily imported from anywhere in the world. Gas is primarily a North American commodity. Imports (other than Canadian pipeline imports) can impact the market only when domestic prices are high – and even then we have to compete with Japan and other regular customer on the world market. At the current low price of gas (relative to oil), the United States may become a gas exporter.
The transportability of oil caused the oil-oriented major integrated companies to focus their exploration efforts overseas when drilling and production costs rose in the U.S. Finding large deposits of oil overseas was easier, cheaper and more efficient than it was in the States. The U.S. natural gas market became the domain of domestic independents.
Policy decisions have taken much of the domestic oil resource base off the table, namely in the Alaskan North Slope, much of the Mountain West and the 85% of the Outer Continental Shelf which is closed to exploration. We cannot know how big this potential resource base is until we drill it. Many would prefer not to know, whether for political or environmental reasons, so we can expect the fight to continue.
“Gold is where you find it, according to an old adage, but judging from the record of our experience, oil must be sought first of all in our minds.” – Wallace E. Pratt, Chief Geologist at Humble Oil and Refining.
Notes on terminology
Cumulative Production is the amount of a resource that has been produced to date.
Remaining Resource is the currently accepted term for the amount of that resource that will be produced in the future.
Ultimate Resource = Cumulative Production plus Remaining Resource. In this paper I have used “Estimated Ultimate Recovery” (EUR) or “resource base” interchangeably with Ultimate Resource.
Remaining Reserves, Proved Reserves and SEC Reserves are used interchangeably to mean the quantity of future production that is expected to be recovered with relative certainty, and under existing technology and economic conditions, from existing wells plus nearby offset locations. Reserves are subsets of the Remaining Resource.
The other component of the Remaining Resource is the Undiscovered Resource, that quantity that will be discovered and produced from new sources and new basins. It is subject to much less certainty than “reserves”. The Potential Gas Committee (PGC) quantifies the “Undiscovered Technically Recoverable Resource”, which tallies the resource thought to be recoverable with known methods, regardless of economics.
To add more confusion, this nomenclature was not yet standardized in Hubbert’s day, so he sometimes used the term “reserves” when he meant “resources”.
References
[1] M. King Hubbert, “Nuclear Energy and the Fossil Fuels”, presented to the Southern Division of the American Petroleum Institute, San Antonio, March 1956. http://www.hubbertpeak.com/hubbert/1956/1956.pdf
[2] M. King Hubbert, “U.S. Petroleum Estimates 1956-1978”, presented at the annual meeting of the American Petroleum Institute Production Department, Denver, April 1978.
[3] Report of the Potential Gas Committee (December 31, 2010): Potential Supply of Natural Gas in the United States. http://www.narucmeetings.org/Presentations/PGC%20NARUC%20Committee%20on%20Gas%20July%2018,%202011.pdf
[4] C. Paul Hilliard, personal interview.
[5] Newark East (Barnett Shale) Field : http://www.rrc.state.tx.us/barnettshale/index.php
[6] As quoted by Daniel Yergin in The Wall Street Journal Online Saturday Essay: “There Will Be Oil” (September 17, 2011). http://online.wsj.com/article/SB10001424053111904060604576572552998674340.html
Natural gas data from the Energy Information Administration (http://eia.doe.gov). Gas production figures are “U.S. Natural Gas Marketed Production” (Sourcekey N9050US2) less Alaska volumes (N9050AK2). Average U.S. wellhead price (N9190US3)
U.S. GDP Deflator: http://www.measuringworth.com/usgdp/
Cross-posted at stevemaley.com and RedState.com.
Maley's Energy Blog 
As an engineer, I am sure there is a finite supply, we already know existing fields in production eventaully get fully exhausted. Yes there are new methods that will extract more, but it gets tougher. But there is also a lot of the US that we haven’t really explored. Like 10 years ago what were the predictions for reserves in Ohio, not much and not much chance. We will begin to know when we have hit the limit when the amount of proven reserves added in a year are consistantly less than the amount extracted.
We should go for the reserves available now, but also work on the next energy sources like nuclear (fission) and fusion. Tidal and other renewables can make a play, but we really need to connect them to tasks that can come and go with the wind or sun. Pumping oil, gas, or water when the wind blows would match this up.
Great blog BTW
Well, there obviously is a finite supply, as the planet is of finite size, but I suspect that there are far more hydrocarbons in the earth than we will ever be able to extract. Consider the formation of the earth. A soup of elements were drawn together by gravity. Then the heavier elements were drawn towards the center of the earth until we reached the state we are in now; our planet has a core comprised of heavy elements like iron, a mantle, and a thin veneer of a crust. We have only really explored the crust.
If you take hydrogen, oxygen, carbon and nitrogen and combine them under extreme pressures and temperatures, the result is hydrocarbons. What if our planet is soaked through with hydrocarbons — formed deep underground under high pressure from the mass above them and high temperature from the planet’s liquid iron core — slowly simmering through the mantle to form deposits near the crust. Remember where helium comes from. It is extracted from natural gas. If oil and gas are really “fossil fuels”, then where does the helium come from? The helium is obviously filtering through the planetary mass and coming out with the natural gas. Why don’t we find pure helium when we dig? Why not helium-free natural gas? And why would we believe that hydrocarbons only exist near the surface? The mass of the crust is miniscule compared to the mantle.
This completely changes the picture of so-called “fossil fuels.” Instead of thinking of fossil fuels as static deposits that will be used up and never replenished, it is probably more correct to think of them as a natural resource being constantly provided by the planet. The oil and gas production of the 20th century should be considered as the picking of the low-hanging fruit — the recovery of easy-to-recover pools of collected hydrocarbons. But what if we were to dig much deeper — down to levels where hydrocarbons more freely migrate through the planetary mass?
Tap that, and all the oil recovered in the history of the world will be a drop in comparison.
You’re talking about aboitic oil. I wouldn’t bet on it.
The conventional view is that oil and gas result from the burial of organic matter in shale rocks. Time, pressure and temperature cook it into hydrocarbons. To me, the success of horizontal drilling in shales lends that theory all the more credence.
Helium is found in gas only in certain limited geographic areas. It likely did migrate from deeper within the earth.
I suspected that there was a name for this theory, but I never knew what it was. Thanks. Now I have a lot more to read about.
so is hubberts theory correct or not?
Not.
It’s only valid if you assume the ultimate recovery of a resource is a fixed quantity. It was adapted from hard-rock mining, where I suppose it has some applicability.
Hubbert was wrong because his concept of where we would find oil and gas was limited by the technology and economics of his time. Especially for gas, we have greatly outstripped his estimates. For oil, we are finding it in places where he didn’t even know to look.
1999
Dick Cheney’s speech to the London Petroleum Institute 1999
http://www.energybulletin.net/node/559
From the standpoint of the oil industry obviously and I’ll talk a little later on about gas, but obviously for over a hundred years we as an industry have had to deal with the pesky problem that once you find oil and pump it out of the ground you’ve got to turn around and find more or go out of business. Producing oil is obviously a self-depleting activity. Every year you’ve got to find and develop reserves equal to your output just to stand still, just to stay even. This is true for companies as well in the broader economic sense as it is for the world. A new merged company like Exxon-Mobil will have to secure over a billion and a half barrels of new oil equivalent reserves every year just to replace existing production. It’s like making one hundred per cent interest discovery in another major field of some five hundred million barrels equivalent every four months or finding two Hibernias a year.
For the world as a whole, oil companies are expected to keep finding and developing enough oil to offset our seventy one million plus barrel a day of oil depletion, but also to meet new demand. By some estimates there will be an average of two per cent annual growth in global oil demand over the years ahead along with conservatively a three per cent natural decline in production from existing reserves. That means by 2010 we will need on the order of an additional fifty million barrels a day. So where is the oil going to come from?
Governments and the national oil companies are obviously controlling about ninety per cent [90%] of the assets. Oil remains fundamentally a government business. While many regions of the world offer great oil opportunities, the Middle East with two thirds of the world’s oil and the lowest cost, is still where the prize ultimately lies, even though companies are anxious for greater access there, progress continues to be slow. – Dick Cheney, CEO Halliburton.
World’s Largest Oil and Gas Companies
Exxon ranks 17th. The 16 larger companies are nationalized oil companies who control 90% of the reserves: http://www.petrostrategies.org/Links/Worlds_Largest_Oil_and_Gas_Companies_Sites.htm
2001
VP Dick Cheney’s Energy Task Force
National Energy Policy Development Group (NEPDG)
http://en.wikipedia.org/wiki/Energy_Task_Force
“America faces a major energy supply crisis over the next two decades,” Secretary of Energy Spencer Abraham told a National Energy Summit on March 19, 2001. “The failure to meet this challenge will threaten our nation’s economic prosperity, compromise our national security, and literally alter the way we lead our lives.” The Energy Task Force was developed to decrease American dependency on foreign petroleum, which the National Energy Policy deemed would have a negative effect on the US economy, standards of living and national security.[6]
The Task Force was composed of Vice President Dick Cheney and the Secretaries of State, Treasury, Interior, Agriculture, Commerce, Transportation and Energy, as well as other cabinet and senior administration-level officials. According to the GAO, these members held ten meetings over the course of three and a half months with petroleum, coal, nuclear, natural gas, and electricity industry representatives and lobbyists. None of the meetings were open to the public and no non-federal participants were involved.
2008
International Energy Agency (IEA)
IEA World Energy Outlook 2008
Click to access WEO2008SUM.pdf
Main text
The projected increase in global oil output hinges on adequate and timely investment. Some 64 mb/d of additional gross capacity — the equivalent of almost six times that of Saudi Arabia today — needs to be brought on stream between 2007 and 2030. Some 30 mb/d of new capacity is needed by 2015. There remains a real risk that under-investment will cause an oil-supply crunch in that timeframe. The current wave of upstream investment looks set to boost net oil-production capacity in the next two to three years, pushing up spare capacity modestly. However, capacity additions from current projects tail off after 2010. This largely reflects the upstream development cycle: many new projects will undoubtedly be sanctioned in the near term as oil companies complete existing projects and move on to new ones. But the gap now evident between what is currently being built and what will be needed to keep pace with demand is set to widen sharply after 2010. Around 7 mb/d of additional capacity (over and above that from all current projects) needs to be brought on stream by 2015, most of which will need to be sanctioned within the next two years, to avoid a fall in spare capacity towards the middle of the next decade.
That is the equivalent of the oil industry needing to put online a new Saudi Arabia every 3.8 years.
(2030 – 2007) / 6 = 3.8
IEA Word Energy Outlook 2008 Press Release
http://www.iea.org/Textbase/press/pressdetail.asp?PRESS_REL_ID=275
The prospect of accelerating declines in production at individual oilfields is adding to these uncertainties. The findings of an unprecedented field-by-field analysis of the historical production trends of 800 oilfields indicate that decline rates are likely to rise significantly in the long term, from an average of 6.7% today to 8.6% in 2030. “Despite all the attention that is given to demand growth, decline rates are actually a far more important determinant of investment needs. Even if oil demand was to remain flat to 2030, 45 mb/d of gross capacity – roughly four times the current capacity of Saudi Arabia – would need to be built by 2030 just to offset the effect of oilfield decline”, Mr. Tanaka added
That would be the equivalent of putting a new Saudi Arabia being put online every 5 years just to keep global oil supply at current production capacity.
2009
National Geographic Magazine:
http://ngm.nationalgeographic.com/print/2009/03/energy-challenge/mckibben-text
“The Energy Information Administration, an arm of the U.S. government, forecast last year that, all things being equal, world energy consumption would increase 50 percent by 2030. That’s a good round number, summing up the desire of people across the world for refrigerators, televisions, ice cubes, hamburgers, motorbikes, and maybe even a little air-conditioning in the tropics.”
“But it’s not at all clear where that energy can come from, because we happen to be alive at the moment when the oil is starting to run out. In November 2008 the International Energy Agency (IEA) estimated that production from the world’s mature oil fields was declining 6.7 percent a year, a rate that is expected to get even worse over time. Offsetting this decline will require finding a new Kuwait’s worth of output every year, or somehow squeezing that much more from existing fields. Many observers think we’ve already passed the peak of oil production. An optimist in this world is someone who thinks it might still be a matter of years. But there’s little question where the future lies, which is why the cost of a barrel of oil spiked to $147 last year. It took the prospect of a Great Recession to bring it back down to $40. Curbing high gas prices with recurrent economic slumps is probably not the smartest of remedies.”
2010
United States Joint Forces Command:
U.S. JOINT OPERATING ENVIRONMENT REPORT 2010 (JOE Report 2010) http://www.fas.org/man/eprint/joe2010.pdf
“A severe energy crunch is inevitable without a massive expansion of production and refining capacity. While it is difficult to predict precisely what economic, political, and strategic effects such a shortfall might produce, it surely would reduce the prospects for growth in both the developing and developed worlds. Such an economic slowdown would exacerbate other unresolved tensions, push fragile and failing states further down the path toward collapse, and perhaps have serious economic impact on both China and India. At best, it would lead to periods of harsh economic adjustment. To what extent conservation measures, investments in alternative energy production, and efforts to expand petroleum production from tar sands and shale would mitigate such a period of adjustment is difficult to predict. One should not forget that the Great Depression spawned a number of totalitarian regimes that sought economic prosperity for their nations by ruthless conquest…By 2012, surplus oil production capacity could entirely disappear, and as early as 2015, the shortfall in output could reach nearly 10 million barrels per day…The implications for future conflict are ominous, if energy supplies cannot keep up with demand and should states see the need to militarily secure dwindling energy resources.”
Dept of Energy EIA:
http://www.eia.doe.gov/neic/infosheets/petroleumproductsconsumption.html
US Daily Consumption of oil is 19.180 million barrels per day. 8.993 million barrels of that is consumed as finished motor fuel gasoline. To put that into perspective the U.S. JOINT OPERATING ENVIRONMENT REPORT estimate of 10 million barrel per day global shortfall by 2015 would the equivalent of having every gasoline pump across all 50 states gone dry. Picture all US roads vacant of gasoline autos. That’s what a 10 million barrels shortfall represents.
2011
German Military: Armed Forces, Capabilities and Technologies in the 21st Century
Environmental Dimensions of Security
Click to access Peak%20Oil_Study%20EN.pdf
5. Conclusion
Gaining an illustrative picture of a subject is very much a matter of habit. When
considering the consequences of peak oil, no everyday experiences and only few historical
parallels are at hand. It is therefore difficult to imagine how significant the effects of being
gradually deprived of one of our civilisation’s most important energy sources will be.
Psychological barriers cause indisputable facts to be blanked out and lead to almost
instinctively refusing to look into this difficult subject in detail.
Peak oil, however, is unavoidable. This study shows the existence of a very serious risk
that a global transformation of economic and social structures, triggered by a long-term
shortage of important raw materials, will not take place without frictions regarding
security policy. The disintegration of complex economic systems and their interdependent
infrastructures has immediate and in some cases profound effects on many areas of life,
particularly in industrialised countries.
According to the results of this study, the developments in the wake of peak oil will involve
major uncertainties for Germany. While it is possible to identify specific risks, this does
not conceal the fact that the majority of the challenges we are facing are still unknown.
Besides adapting economic and energy supply policy at an early stage and not only in
highly industrialised countries, the probably most effective solution strategies are thus not
concerned with specific countermeasures but with systemic “cardinal virtues” such as
independence, flexibility and redundancy. Efforts must be made on a cross-government
and multi-level basis to better understand and control the complex dependences of
infrastructures and highly differentiated value-added chains. In this connection, it is
necessary to rethink evaluation standards. Not only efficiency but also, to an increasing
extent, robustness becomes a criterion of sustainable policy.
To Interk: Do your research on the Siljin Ring Theory for Abiotic gas, drilled in a Granitic formation struck by a meteorite in northern Sweden.
A partial list of products made from Petroleum (144 of 6000 items), not natural gas
http://www.ranken-energy.com/Products%20from%20Petroleum.htm
There are 4 million miles of asphalt paved roads in the US (http://www.nationalatlas.gov/transportation.html) that require periodic maintenance. Asphalt averages 1 1/2% of a barrel by volume. You will not be paving roads with natural gas.
Charles Maxwell
on peak oil and natural gas taking 20-30 years.
Oil execs:
http://www.youtube.com/user/OilEducationTV#p/u/2/oZp-OxZuflE
http://www.youtube.com/user/OilEducationTV#p/u/3/4d3kK4kgz5g
How much oil does the world consume? Visualize this many 55-gallon steel drums:
World daily oil consumption: 88 million 42-gallon barrels
A 55 gallon steel drum is 3 feet tall
A mile is 5,280 feet
The circumference of the earth is 24,901 miles
The speed of sound (Mach 1) is 768mph
If you convert barrels to steel drums.
(88,000,000 x 42gal) / 55gal = 67,200,000 steel drums
If you laid those drum end to en on their side (as though you were making a pipeline of steel drums), how long would this pipeline be?
(67,200,000 x 3ft) / 5,280 = 38,182 miles long
At 38,182 miles you would encircle the earth 1 1/2 times each day
38,182 / 24,901 = 1.53 or 1 1/2 times
or you could encircle the earth with steel drums 560 times each year.
(38,182 miles x 365days) / 24,901 = 560 times around the earth each year.
And the speed at which you’d have to lay those drums down?
The speed at which you’d have to lay those drums end to end to cover the 38,182 mile distance?
(38,182 miles per day / 24 hours) = 1,591mph
1,591mph / 768mph = 2.07 or Mach 2
Environmentalists who believes we will replace those petroleum volumes with veggie oils and white-lighting whiskey is playing with a full deck.
dude, oil is NOT gas.
Oh wait, there’s an endless supply of oil and gas right? Natural resource are a stepping stone to true infinite energy, like sun and wind.
Dude, thanks for pointing that out.
As a petroleum engineer, I’ve always found that confusing. You know what else is confusing? When they call gasoline “gas”, when it’s not really a gas, but a liquid!
Dude!
Vlad: You kill me.
I have always found “polish” and “Polish” so confusing. How can a single word change definitions so … er … difinitively just by capitalizing the first letter.
DUDE!
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Steve,
You note above that “From 1981 until 1985, the count of active drilling rigs declined from 4,500 to 700.” Do you have the reference for this data point?
Thanks (and thanks for the write up–it’s quite interesting).
https://www.rigzone.com/news/oil_gas/a/74065/musings_rig_count_downturn_moves_into_uncharted_territory/
It’s etched in my memory — I lived it.
My Mom was working for a small family-owned contract driller in Tulsa. In late 1981, the owner/patriarch decided it was time to sell the rigs. His sons, each of whom pushed tools on one of the company’s rigs, thought he was nuts.
I was working for an independent co. in Tulsa at the time, a subsidiary of a large gas pipeline. We were very busy, especially in the Deep Anadarko Basin where things were very active, spending about $225 million a year drilling wells from the Gulf Coast to Canada.
Around the corner from my office was Gas Marketing — 2 guys whose jobs it was to administer gas contracts, back then a pretty sleepy job. One day about the same time, the manager emerged from his office, looking stunned.
“That’s weird. We just got a call from XYZ Transmission telling us they don’t want the gas from the Schultz #1.”
Guy#2: “Why, we just brought that well on! They can’t shut us in! Don’t they know we have a take-or-pay contract?!”
What we learned is that when you’re a sub of a gas company yourself, threatening to sue other pipelines for take-or-pay isn’t an idea that’s going anywhere.
That company never saw 1987.
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