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Peak oil is not a myth | Chemistry World

Peak oil is not a myth | Chemistry World.

20 February 2014
One might have the impression that hydraulic fracturing (fracking) of shale deposits is the answer to world energy security. Certainly fracking has received much attention and investment, but its prospects must be considered in a broader context.
In the US, where practically all such operations have been conducted to date, fracking now accounts for 40% of domestic gas production and 30% of oil production. The price of natural gas has plummeted, and overall US oil production has increased for the first time since 1970, which had otherwise been falling in accordance with the predictions M King Hubbert made in 1956.
© Shutterstock

However, this last point is the salient one. Sources of unconventional oil (listed below) such as tight oil (or ‘shale oil’ in popular discourse) are only commercially viable because the need to match the declining rate of conventional oil production has raised oil prices. It is the rate of production of oil that determines its supply, rather than the size of the reserves: ‘The size of the tap, not the tank.’

Oil check

Current data for the decline in oil fields’ production indicates that around 3 million barrels per day of new production must be achieved year on year, simply to sustain supply levels. This is equivalent to finding another Saudi Arabia every 3–4 years. In this context, fracking is at best a stop-gap measure. Conventional oil production is predicted to drop by over 50% in the next two decades and tight oil is unlikely to replace more than 6%.
Once conventional oil’s rate of loss exceeds unconventional oil’s rate of production, world production must peak. Production of sweet, light crude actually peaked in 2005 but this has been masked by the increase in unconventional oil production, and also by lumping together different kinds of material with oil and referring to the collective as ‘liquids’. (More recently, the term ‘liquids’ is often upgraded to ‘oil’, which is highly disinformative since the properties of the other liquids are quite different from crude oil.)
Fracking produces mostly shale gas (rather than oil), and the major growth in global ‘oil’ production has been from natural gas liquids (NGL; in part from shale gas). But the principal components of NGL are ethane and propane, so it is not a simple substitute for petroleum.

Energy in, energy out

The energy return on energy invested (EROEI) is worse for all unconventional oil production methods than for conventional oil.

‘Oil production is predicted to drop by over 50% in two decades’

This means that more energy must be invested to maintain output. As a rough comparison, conventional crude oil production has an EROEI in the range 10–20:1, while tight oil comes in at 4–5:1. Oil recovered from (ultra)deepwater drilling gives 4–7:1, heavy oil 3–5:1, and oil shale (kerogen) somewhere around 1.5–4:1. Tar sands is around 6:1, if it is recovered by surface mining, but this falls to around 3:1 when the bitumen is ‘upgraded’ by conversion to a liquid ‘oil’ substitute.

As conventional oil production has fallen, so has oil’s EROEI as we recover it from increasingly inhospitable locations, and with new technologies. The price of a barrel of oil has trebled over the past decade, but output has effectively flatlined. We may be close to the ceiling of global oil production, and the prospect of filling the gap with oil from alternative sources is daunting.

Different rocks

Although fracking has produced sizeable volumes of oil and gas in the US, there is no guarantee that a similar success will be met elsewhere, including the UK, in part because the geology is different. Even in the US, it is the sweet spots that have been drilled, and the shale plays elsewhere across the continent are likely to prove less productive.
The shale gas reserves in Poland have been revised down from 187 trillion cubic feet (tcf) to 12–27 tcf: at best, a mere 14% of the original estimate. And most of the production is likely to be gas. Even if we can exhume large volumes of gas at a generous production rate, converting our transport system to run on it would be a considerable undertaking, particularly given the timescale imposed by conventional oil production’s rate of decline. And there are many uses for oil other than to provide liquid fuels, for which substitutes must also be found.
Renewables do not provide a comparable substitute for crude oil and the liquid fuels that are refined from it, since the potential contribution from biofuels is relatively minor. Replacing the UK’s 34 million oil-powered vehicles with electric versions is an unlikely proposition, given the limitations of time and resources such as rare earth metals. Mass transit is the more likely future for electric transport than personal cars. The end of cheap, personal transport is a real possibility and may seed changes in our behaviour, such as building resilient communities that produce more of their essentials, such as food and materials, at the local level.
There are many uncertainties, but it seems clear that the age of cheap oil is over. We are entering a very new and different phase of human experience.
Chris Rhodes is an independent consultant based in Reading, UK, and author of  University shambles

Peak Oil Is Here Despite Industry Claims  |  Peak Oil News and Message Boards

Peak Oil Is Here Despite Industry Claims  |  Peak Oil News and Message Boards.

The oil industry wants us to believe that North America is sitting on an endless supply of natural gas and oil – and they want access to all of it.  But the truth is that there is barely enough fossil fuel in the ground to sustain the US. Ring of Fire’s Mike Papantonio speaks with author Michael Klare about how Peak Oil is still a very real threat.

America’s Feel-Good Oil Bonanza

America’s Feel-Good Oil Bonanza.

Think back to early 2004. Oil cost around $40 per barrel1—on the high side compared to the previous few decades but not much out of the ordinary. Gasoline still cost under $2.00 a gallon for most of the country. The evening news was more concerned with wardrobe gaffes by Janet Jackson (too little, at the Super Bowl) and President Bush (too much, on the USS Abraham Lincoln) than with energy prices.

In retrospect, these were the last days of “normal.” Most everyone in business, the media, and government assumed that the world had plenty of cheap oil.2 And hardly anyone outside the fossil fuel industry had heard of peak oil, the idea that we were nearing physical limits to global oil production and a new period of oil price and supply volatility.

We now know that the world’s conventional oil production would effectively stop growing the very next year, setting off a sickening global economic rollercoaster ride. The complacency of 2004 would change to worry by 2005 as the price of oil surged past historic highs, and to outright panic in 2008 when it crossed the once-unthinkable $100 barrier. It would spark massively increased investment in alternatives like tight oil, tar sands oil, shale gas, renewable energy, and nuclear power—all while the global economy made painful adjustments to the new normal of $80-plus oil.

By now you’d think we’d be chastened by the last ten years, and would be planning cautiously and conservatively for our nation’s energy future. Instead, almost everyone is once again assuming that we’ve got plenty of (admittedly more expensive) oil, and that there’s nothing to worry about.

Such shortsightedness isn’t necessarily surprising for Wall Street, where only the current quarter’s figures matter; nor for the news media, where energy-literate journalists are sadly few and far between. But it’s quite another matter to see it in a federal government agency, especially one whose most important functions include projecting the future of the country’s energy needs and resources.

In this respect, the Energy Information Administration’s (EIA) recently releasedAnnual Energy Outlook 2014 (AEO 2014), which foresees impending and long-term US oil abundance, is not just surprising—it’s a dangerous return to a 2004 way of thinking.

California Dreaming

Lest you think the projections issued by a relatively small government agency are immaterial to real-world decisions about the world’s most important resource, consider the case of the Monterey shale. Two years ago the EIA released a 105-page assessment of technically recoverable shale gas and tight oil in the lower-48 states.3 Among other things, it estimated a massive amount of tight oil in California’s Monterey formation: 15.4 billion barrels, or over 64% of the country’s projected total tight oil resource base.

America’s supposed new oil nest egg was quickly accepted as unquestionable fact. The New York Times4Wall Street Journal5, CNN6, and countless other media outlets reported it uncritically. It became a central argument in the fossil fuel industry’s efforts to influence California’s regulations on drilling and new technologies like fracking.7 And one can only assume that the 15.4 billion barrel worm made its way into the ears of politicians and policymakers across the country, whispering, “We’ll have decades of American energy independence!”

Of course, a deus ex machina like this raised more than a few eyebrows, including here at Post Carbon Institute; so we looked into it.8 We found that the EIA report’s authors9 had tallied up 15.4 billion barrels simply by assuming that every square mile of the Monterey would be more productive than practically all the best areas in America’s two best tight oil plays, the Bakken shale (in North Dakota) and the Eagle Ford shale in Texas. That’s it. No consideration of the Monterey’s significant geological complexity compared to the two plays, nor of data from actual Monterey oil production. In other words, our new cornerstone of energy independence rested on a back-of-the envelope calculation that any first-year petroleum geology student would recognize as unrealistic.

But simply because it was published by the EIA, the 15.4 billion barrel worm went on to influence some of America’s most important policy and planning decisions for over two years—unquestioned and unchallenged.

So, what the EIA says matters—regardless of its veracity or substantiation. In this light, let’s take a look at what the EIA is now saying in AEO 2014.

Saudi America

The most-repeated nugget from AEO 2014 is the projection that US oil production will reach 9.61 million barrels per day (mbd) by 2019, matching its historic peak of 1970.10 Less-repeated but just as important is the projection that after 2021 US oil production will start a very gradual decline, leaving us in 2040 with daily production at a respectable 7.48 mbd (which happens to roughly be 2013’s average daily production).11 It’s an energy patriot’s dream come true—an imminent, rapid rise in domestic production to give a boost to the economy, followed by a gradual tapering-off that will allow for an orderly transition to alternative energy sources.

[chart]

This rosy projection is driven by significant and sustained production of tight oil from shale formations (enabled by fracking and other technologies)—a cumulative total of 42.8 billion barrels by 2040. Anyone who’s not a petroleum geologist might be forgiven for assuming this means the EIA has a pretty good idea where that 42.8 billion barrels is and how it will realistically be produced. As we’ll see, this is not the case.

Most of America’s tight oil—about 74%—currently comes the aforementioned Bakken and the Eagle Ford plays. These look set to peak as soon as 2016-2017, although they could possibly recover a total of 11 billion barrels by 2035 if 48,000 new wells can be drilled (five times the current total).12 However, the Bakken and the Eagle Ford are the best we’ve got; none of America’s other tight oil plays look to have such high-producing wells over such large areas. Producing an additional 31 billion barrels by 2040 from increasingly marginal (and thus more expensive) plays is a real stretch.

A quick look behind the EIA’s numbers further undermines confidence. According to the assumptions underlying last year’s Annual Energy Outlook (the equivalent background material is not yet available for 2014), the EIA sees total recoverable tight oil resources of 13.7 billion barrels from the Monterey (a recent downward revision from the original 15.4 billion mentioned earlier), 7.3 billion barrels from the Austin Chalk, 5.3 billion barrels from the Permian Basin, and the remainder from a scattering of other plays. They’re impressive numbers…until one remembers the flimsy case behind the Monterey projections.

The EIA also says nothing about the rate of production from wells in these plays, which is critical to profitability and has proved to be an Achilles Heel in other tight oil plays. Production in Eagle Ford tight oil wells, for example, declines 60 percent on average in their first year; in the Bakken it’s 69 percent.13 This means more wells must constantly be drilled to keep overall production from collapsing. But there is a physical limit to the number of wells that can be usefully drilled in an area; once that limit is reached (in the Bakken and Eagle Ford it could be within the next 10-12 years depending on drilling rates14), production will decline sharply.

A perennial argument against such pessimism is that more oil resources will become accessible as rising oil prices make the more technically challenging oil economic to produce. However, in AEO 2014 the EIA actually expects the price of oil to drop to as low as $88 per barrel by 2018, and thereafter rise at a meager 1.5-2.5% per year15—about the rate of inflation the last few years.

Is the forecast that the United States will hit 9.61 million barrels of day of oil in 2019 credible? Perhaps, if everything goes right and capital inflows don’t falter; the forecast is largely driven by measurable results from the most productive areas of the Bakken and the Eagle Ford.16 But once those are tapped out, there’s scant evidence for a future in which the oil produced from the remaining tight oil plays will amount to nearly four times as much as from the Bakken and Eagle Ford—let alone that tight oil production will decline only gradually over the following 20 years. Indeed, one must conclude that the EIA’s projection assumes that future technological innovations will make it economical to produce currently unprofitable oil despite oil prices hardly changing.

Reality Check

A more prudent, conservative US oil forecast would look very different. It would consider that, although surprises are always possible, the most productive fossil fuel resources do tend to be discovered first and produced first. It would take note of the fact that production in fracked wells declines extremely quickly, requiring an accelerating drilling treadmill to maintain—let alone grow—production, with associated collateral environmental impacts. It would assume that most tight oil plays producible at current oil prices have already been discovered and put into production, and that major new resources—if they exist—are unlikely to be forthcoming unless there is a significant rise in oil prices.17 In short, the forecast would be based on actual data from existing and legitimately forthcoming plays, and leave the feel-good speculation about future resource abundance to Wall Street.

This is no small matter. The projected availability and price of future oil directly impacts decisions being made today about everything from factory expansions to multi-billion dollar transportation projects. It influences federal government policy on encouraging (or discouraging) gas mileage standards, electric vehicles, building efficiency, and renewable energy. And it certainly colors the debate around regulating the exploration and production of fossil fuels in communities and public lands across the country.

That last debate is playing out in California right now, as the fossil fuel industry pushes legislators to relax environmental laws to allow more development of tight oil in the Monterey shale via fracking and acidization. The heightened risk of environmental damage caused by developing Monterey tight oil may seem acceptable to legislators who believe 15.4 billion barrels of oil, $24.6 billion per year in tax revenue, and 2.8 million jobs18 are in the offing—though far less so if the recoverable oil is actually a small fraction of that (which our report Drilling California concluded is likely the case19).

The stakes are also sky-high with respect to the national economy. The EIA sees US oil imports remaining relatively low throughout 2040 thanks to the supposed windfall of domestic tight oil production. If they’re wrong, oil imports would have to make up the difference, adding to our already substantial monthly petroleum trade deficit of $20 billion per month.20 And, of course, the price of oil would go up—possibly significantly—until global demand balances with the new, reduced, global supply.21

Conclusion

The EIA’s yearly publication of the Annual Energy Outlook is, without a doubt, an enormously challenging undertaking. Each year’s AEO pulls together projections that involve extremely large sets of data, endless analysis of industries and economies, and—of necessity—significant assumptions and caveats. The EIA’s own retrospectives on the accuracy of its projections reveal, however, that it generally overestimates oil production and underestimates price.22 Nevertheless, once the EIA’s annual projections are released they’re inevitably treated as future fact by the media and the public.

Although few would disagree that the EIA’s data collection and dissemination activities are world-class, its projections in AEO 2014 are, like most of its previous projections, overly optimistic and unlikely to be realized. The risks to long-term American energy security are obvious if the EIA’s projections of low-priced energy abundance don’t work out.

Good news sells, and doesn’t rock any boats, but policy makers and politicians comforted by rosy forecasts are unable to understand the risks and properly prepare the country for long-term energy sustainability. It’s unfortunate—and yes, dangerous—that rosy forecasts are exactly what the government’s premiere energy fortuneteller continues to offer, despite its dismal track record.
ENDNOTES

1 In 2013 dollars.

2 The EIA’s Annual Energy Outlook 2005 reference case oil price for 2025 was around $30 (~$37 in 2013 dollars). http://www.eia.gov/forecasts/archive/aeo05/pdf/0383(2005).pdf

8 J. David Hughes, Drilling California: A Reality Check on the Monterey Oil (Santa Rosa, CA: Post Carbon Institute, 2013), http://montereyoil.org.

9 The report was authored by a contractor, INTEK, Inc., but published by the EIA with an EIA-written introduction.

10 Energy Information Administration, Annual Energy Outlook 2014 (Early Release); figures include crude oil and lease condensate. These projections are not to be confused with those of the International Energy Administration’s World Energy Outlook 2013 which, because it includes natural gas liquids, sees the United States being the world’s top producer in 2015.http://www.bloomberg.com/news/2013-11-12/u-s-nears-energy-independence-by-2035-on-shale-boom-iea-says.html

11 Energy Information Administration, Annual Energy Outlook 2014 (Early Release), Table 14. The EIA includes non-tight-oil liquids in these numbers that happen to come from tight oil plays.

12 J. David Hughes, “Tight Oil: A Solution to U.S. Import Dependence?,” presentation to Geological Society of America, Denver, Colorado, October 28, 2013,https://gsa.confex.com/gsa/2013AM/webprogram/Handout/Paper226205/HUGHES%20GSA%20Oct%2028%202013%20-%20Short.pdf.

13 J. David Hughes, Drill Baby Drill: Can Unconventional Fuels Usher in a New Era of Energy Abundance? (Santa Rosa, CA: Post Carbon Institute, 2013), http://shalebubble.org/drill-baby-drill/.

14 J. David Hughes estimates this could happen within 10-12 years in the Bakken and Eagle Ford; seehttps://gsa.confex.com/gsa/2013AM/webprogram/Handout/Paper226205/HUGHES%20GSA%20Oct%2028%202013%20-%20Short.pdf.

15 Energy Information Administration, Annual Energy Outlook 2014 (Early Release), Table 14.

16 According to J. David Hughes, $450 billion in capital expenditures (capex) will be required to drill the wells needed for the Bakken and Eagle Ford alone by 2025. The Permian Basin will also make a notable contribution to the 9.61 mbd figure.

17 See especially Art Berman’s comments on capital expenditures in Arthur Berman, “Reflections on a Decade of U.S. Shale Plays,” presentation at Shreveport Geological Society, Louisiana, December 17, 2013. http://www.jeremyleggett.net/wp-content/uploads/2013/12/SGS_Reflections-on-A-Decade-of-U.S.-Shale-Plays_17-Dec-2013.pdf.

18 Per this widely cited report: University of Southern California, USC Price School of Public Policy, The Monterey Shale and California’s Economic Future, (March 2013),http://gen.usc.edu/assets/001/84955.pdf.

19 J. David Hughes, Drilling California: A Reality Check on the Monterey Shale, (Santa Rosa, CA: Post Carbon Institute, 2013), http://montereyoil.org/report.

21 It’s unlikely that a significant amount of “lost” American tight oil would be compensated with increased production elsewhere without higher oil prices, as few areas of the world are expecting significant oil production growth outside of North America.

22 In his book Snake Oil Richard Heinberg notes that “during the past dozen years the [EIA] had underestimated oil prices and overestimated oil production most of the time” based on the EIA’s own AEO Retrospective Review published March 2013.http://www.eia.gov/forecasts/aeo/retrospective/

The future of oil supply

The future of oil supply.

journal_logo

  1. Richard G. Miller1 and
  2. Steven R. Sorrell2

+Author Affiliations


  1. 180 Howards Lane, Addlestone, Surrey KT15 1ES, UK

  2. 2Sussex Energy Group, SPRU (Science and Technology Policy Research), University of Sussex, Jubilee Building, Falmer, Brighton BN1 9QE, UK
  1. e-mail: richardmiller99@aol.com

Abstract

Abundant supplies of oil form the foundation of modern industrial economies, but the capacity to maintain and grow global supply is attracting increasing concern. Some commentators forecast a peak in the near future and a subsequent terminal decline in global oil production, while others highlight the recent growth in ‘tight oil’ production and the scope for developing unconventional resources. There are disagreements over the size, cost and recoverability of different resources, the technical and economic potential of different technologies, the contribution of different factors to market trends and the economic implications of reduced supply. Few debates are more important, more contentious, more wide-ranging or more confused. This paper summarizes the main concepts, terms, issues and evidence that are necessary to understand the ‘peak oil’ debate. These include: the origin, nature and classification of oil resources; the trends in oil production and discoveries; the typical production profiles of oil fields, basins and producing regions; the mechanisms underlying those profiles; the extent of depletion of conventional oil; the risk of an approaching peak in global production; and the potential of various mitigation options. The aim is to introduce the subject to non-specialist readers and provide a basis for the subsequent papers in this Theme Issue.

1. Introduction

Abundant supplies of cheap natural liquid fuels form the foundation of modern industrial economies, and at present the vast majority of these fuels are obtained from so-called ‘conventional’ oil. Oil accounts for more than one third of global primary energy supply and more than 95% of transport energy use—a critically important sector where there are no easy substitutes. Our familiarity with oil can obstruct recognition of how remarkable a substance it is: oil took millions of years to form from the remains of marine and other organisms; it is only found in a limited number of locations where a specific combination of geological conditions coincide; it possesses an unequalled combination of high energy per unit mass and per unit volume; and it is both highly flexible and easily transportable. One litre of diesel contains enough energy to move a 40 tonne truck three kilometres—a feat that would be impossible with battery-electric propulsion for example. Nonetheless, despite heavy taxation in most countries and historically high global oil prices, a litre of diesel remains cheaper than a cup of coffee.

Oil is a finite and rapidly depleting fossil resource, and the capacity to maintain and grow supply has been a recurrent concern for over 50 years. During the first decade of this century, an increasing number of commentators began forecasting a near-term peak and subsequent terminal decline in the global production of conventional oil—so-called ‘peak oil’. This process was forecast to lead to substantial and sustained disruption of the global economy, with alternative sources of energy being unable to ‘fill the gap’ at acceptable cost on the time scale required. Countering this, other commentators argued that rising oil prices would stimulate the discovery and enhanced recovery of conventional oil, the development of ‘non-conventional’ resources such as oil sands, and the diffusion of substitutes such as biofuels and electric vehicles, without economic disruption. In support of their arguments, the first group cite the plateau in crude oil production since 2005 and the associated rise in oil prices (figure 1), while the latter group cite the recent rapid growth in US tight oil production. But despite these differences, there is a growing consensus that the era of cheap oil has passed and that we are entering a new and very different phase.

Figure 1.

Monthly average crude oil price (right axis) and global oil supply (left axis). Source: US Energy Information Administration. For oil definitions see figure 2 andbox 1. Oil supply has been slow to respond to the doubling of crude oil prices since mid-2005. This is partly because of political conflicts in key regions (e.g. Iraq) and the strategies of key exporters (e.g. Saudi Arabia), but largely reflects the growing lead times on new projects (5–10 years) and the increasing difficulty and cost (up 50% since 2005) of finding and developing new resources. (Online version in colour.)

The contemporary debate over peak oil has its roots in long-standing disputes between ‘resource optimists’ and ‘resource pessimists’ that can be traced at least as far back as Malthus [1]. These disputes are underpinned by the differing perspectives of natural and social scientists, but in the case of oil they are greatly amplified by the difficulties in accessing the relevant data, the unreliability of the data that are available and the pervasive influence of powerful economic and political interests. Moreover, a full appraisal of the challenge posed by oil depletion must extend beyond geological assessments of resource size to include the potential of different extraction technologies, the cost of production of different resources, the operation of global fuel markets, the geopolitics of oil security, and the technical and economic potential for both efficiency improvements and resource substitution in multiple end-use sectors. In practice, few studies can adequately address this complexity.

In this paper, we introduce the data, concepts, terms and evidence that underlie this debate and provide a foundation and context for the papers that follow. The paper is structured as follows. Section 2 summarizes the origin, nature and classification of different types of oil resources, while §3 describes the mechanisms of oil production, the global estimates of resources and reserves and the trends in oil production and discoveries. Section 4 examines the typical production profiles of oil fields, basins and producing regions and shows how these underpin concerns about future supply. Section 5 summarizes the arguments for and against a near-term peak in global oil production and briefly evaluates some mitigation options. Finally, §6 introduces the papers in this Theme Issue.

2. Oil formation and classification

Petroleum comprises all naturally occurring hydrocarbons in rocks, and originates from organic materials (most commonly marine organisms) incorporated into sedimentary rocks.1 These are termed source rocks and are typically fine-grained mudstones or shales. The subsidence and burial of these rocks over geological time raises their temperature and pressure and commences the process of organic maturation. This process first converts the fossilized organic material into an insoluble mixture of extremely large organic molecules, termed kerogen, and then as maturation increases, progressively breaks off smaller hydrogen-rich molecules which form a liquid, leaving an increasingly carbon-rich and refractory kerogen residue. Significant generation of liquid oil typically commences at temperatures around 70°C and continues until 120–160°C, a range called the oil window. Higher temperatures may cause further decomposition of remaining kerogen to produce gaseous C1–C5 hydrocarbons (methane–pentane) and also thermal breakdown of previously generated oil into progressively smaller molecules. The current rate of global oil generation has been estimated at no more than a few million barrels2 per year [3], compared to global consumption of some 30 billion barrels per year. Crude oil production grew at approximately 1.5% per year between 1995 and 2005, but then plateaued with more recent increases in liquids supply deriving from natural gas liquids (NGLs; see box 1), oil sands and tight oil. These trends are expected to continue.

Box 1.

Categories of hydrocarbon liquids.

  • — Crude oil is a heterogeneous mix of hydrocarbons that remain in liquid phase when extracted to the surface. Crude oil is commonly classified by its density, measured in degrees of API gravity with higher API indicating lighter oil.3 Industry definitions vary, but heavy oil is typically less than 20°API.

  • — Condensate is a very light, volatile liquid, typically 50–75° API, which condenses from produced gas when it cools at the surface. Condensate is generally mixed with crude oil and produced volumes are rarely reported separately.

  • — Natural gas liquids (NGLs) is a generic term for the non-methane fraction of natural gas (mostly ethane to pentane) that is either liquid at normal temperatures and pressures, or can be relatively easily turned into a liquid with the application of moderate pressure.

  • — Extra-heavy oil is crude oil with an API gravity of less than 10° and typical viscosity more than or equal to 10 000 centipoise.4 Most current production is from the Orinoco belt in Venezuela.

  • — Oil sands (or tar sands) are a near-surface mixture of sand, water, clay and bitumen, where the latter has an API gravity less than 10° and typical viscosity 10 000–1 000 000 centipoise. The bitumen is the degraded remnant of conventional oil when oil in near-surface accumulations has been altered by the loss of the lighter hydrocarbon molecules, primarily by bacterial oxidation and biodegradation and by dissolution in groundwater. The remaining oil becomes progressively richer in bitumen, denser and more viscous. Most current production is from Alberta and uses surface mining to depths up to 65 m. The bitumen can be diluted or upgraded to a synthetic crude for transport by pipeline.

  • — Tight oil (or shale oil) is light crude oil contained in shale or carbonate rocks with very low permeabilities that can be produced using horizontal wells with multi-stage hydraulic fracturing. Most current production is from the Bakken and Eagle Ford shales in the USA.

  • — Kerogen oil (or ‘oil shale’ oil) is the oil obtained from processing the kerogen contained in fine-grained sedimentary rocks. This involves mining and crushing the rock, heating for prolonged periods at high temperatures, driving off a vapour and distilling. In situ processes are also under development, but neither approach is likely to be economic for the foreseeable future.

  • — Gas-to-liquids (GTLs) are derived through the liquefaction of methane using the Fischer–Tropsch process. This involves steam reforming of natural gas to produce carbon monoxide and hydrogen followed by catalysed chemical reactions to produce liquid hydrocarbons and water.

  • — Coal-to-liquids (CTLs) are derived either by pyrolysis of coal (low yield) or by gasification followed by a Fischer–Tropsch process (high yield).

  • — Biofuels are transport fuels derived from biological sources. At present, these consist of either ethanol produced through the yeast fermentation of sugar or starch-rich arable crops, or biodiesel derived from seed oils. Second generation cellulosic biofuels using non-food feedstocks are also under development.

Mature source rock in contact with adjacent porous rocks may expel generated petroleum down the fluid pressure gradient. If oil cannot be expelled from its source rock it is described as tight oil, a class which includes all oil trapped in impermeable rocks. Expelled oil is less dense than water so will tend to slowly migrate upwards through permeable rocks, replacing pore water. Oil may migrate to the surface and emerge as a seep, but if it reaches an impermeable barrier or seal, in a structure forming a trap, it may accumulate in place as apool within a reservoir rock. Reservoir rocks are primarily characterized by their porosity and permeability, but also by their thickness, continuity, uniformity and lithology (mineralogy, composition and structure). Typical impermeable seal lithologies include shale and salt. An oil pool usually has water-saturated rock underlying it and possibly a gas cap overlying it. An oil play is a specific set of geological conditions, defined by source, maturity, migration route, reservoir, trap and seal, which is conducive to the existence of oil pools within a geographically defined region.

An oil field may consist of one or more separate pools. Generally speaking, oil fields are accumulations large enough to be spatially defined, but are not necessarily economically viable. There is a complete size spectrum of accumulations ranging up to the giant and supergiant fields, which are usually defined as holding more than 500 million and 5000 million barrels of recoverable oil, respectively. The size distribution of commercial fields is fairly well known [4], but the distribution of smaller fields is not, in part because these are neither deliberately sought nor always announced when encountered.

In both individual plays and larger regions (petroleum basins), the majority of oil resources tend to be located within a small number of large accumulations. For example, although there are up to 70 000 producing oil fields in the world, around 500 giant and supergiant fields account for two-thirds of all the oil that has ever been discovered [4]. As discussed later, this basic physical characteristic of oil resources is of critical importance for future supply.

Oil resources are commonly classified into different categories on the basis of physical oil and rock properties, extraction technology or location, but there are inconsistencies in the terminology used. Figure 2 summarizes our classification, while box 1 expands upon these definitions. We define conventional oil as crude oil, condensate and NGLs and non-conventional oil as tight oil, extra-heavy oil, oil sands and kerogen oil. Since tight oil is similar in chemical composition to crude oil (while the other non-conventional oils are not), it could equally be classified as conventional. We classify it as non-conventional here, to emphasize the fact that tight oil is a new and rapidly growing source of liquid fuels that was historically excluded from conventional oil resource estimates and production forecasts. Tight oil also differs from conventional oil in both the geological characteristics of the resource and the methods of production.

Figure 2.

Classification of hydrocarbon liquids. (Online version in colour.)

The core issue for future supply is the extent and the rate of depletion of conventional oil, since this currently provides around 95% of global all-liquids supply. Options for mitigating this depletion include:

  • — substituting conventional oil with non-conventional oil;

  • — substituting all-oil with other non-conventional liquids (gas-to-liquids, coal-to-liquids and biofuels); and

  • — reducing demand for all-liquids (e.g. through improving end-use efficiency, substituting non-liquid energy carriers such as gas or electricity or reducing demand for the relevant energy services).

Both the extent and rate of depletion and the feasibility and cost of different mitigation options are the subject of intense debate.

3. Oil production and resources

Conventional oil has traditionally been recovered through vertical oil wells, drilled through reservoirs from top to bottom. Since these typically contact only a few metres or tens of metres of the reservoir, large reservoirs require multiple wells. Today many wells commence vertically but are then deviated to follow the reservoir. Modern methods allow the drilling of several thousand metres of horizontal sections, thereby increasing access to the edges of the reservoir and achieving higher recovery with fewer wells.

After drilling, oil initially flows to the surface under its own pressure (primary recovery), but this is usually supplemented by pumping and by injecting water or gases into the field to maintain the pressure (secondary recovery). Falling pressure reduces the flow rate and may also permit gas to exsolve from the oil. On average around 35% of the original oil in place can be recovered by these methods [57]. Wells become uneconomic when the oil flow rate becomes too low, particularly when large volumes of water from secondary recovery are co-produced. In later life, many oil wells produce far more water than oil.

The recovery factor may be increased through the use of various enhanced oil recovery (EOR) techniques, such as steam injection, CO2 injection and chemical flooding. These aim to reduce oil viscosity, to block the competing flow of gas or water and/or to drive oil towards the wells. The feasibility of different EOR techniques varies widely from one field to another and they currently account for less than 3% of global production. EOR typically raises recovery factors by 5–15%, but in rare cases total field recovery factors of over 70% can be achieved.

Recovery of tight oil is achieved through a combination of horizontal drilling and hydraulic fracturing (‘fracking’) of relatively impermeable rocks to release oil and gas at economic rates. Recovery of extra-heavy oil can be achieved through a variety of methods, but most commonly by steam injection followed by upgrading and/or dilution for transport by pipeline. Current recovery of oil sands is primarily through open-cast mining, but in situ methods using steam injection are being developed to access much larger deposits at greater depths and with lower environmental impacts. The recovery and conversion of kerogen oil is extremely energy intensive and is little practised on a commercial scale.

(a) Oil production

Global production of all-liquids averaged 85.7 million barrels per day (mb per day) in 2011, or 31.2 billion barrels per year (Gb per year). Global cumulative production amounted to approximately 1248 Gb, with half of this occurring since 1988 (figure 3). Crude oil and condensate5 accounted for 80.0% of all-liquids production in 2011, with the remainder deriving from NGLs (14.1%) and non-conventional liquids (5.9%) (figure 4). Crude oil production grew at approximately 1.5% per year between 1995 and 2005, but then plateaued with more recent increases in liquids supply largely deriving from NGLs, oil sands and tight oil. These trends are expected to continue—for example, the International Energy Agency (IEA) [8] projects NGLs accounting for 19% of global all-liquids production by 2035, and unconventional oil 13.6% (figure 15). On a per capitabasis, annual all-oil production peaked at 5.5 barrels in 1979 and has remained around 4.5 barrels since the mid-1980s. Annual consumption averages approximately 2.5 barrels per person in non-Organization for Economic Co-operation and Development (OECD) countries (82% of the global population) and approximately 14 barrels per person in the OECD, with the USA an outlier at 25 barrels per person.

Figure 3.

Global trends in all-oil production. Source: IHS Energy. Includes crude oil, condensate, NGLs, tight oil, heavy oil and syncrude from oil sands. (Online version in colour.)

Figure 4.

Breakdown of global all-liquids production in 2011 (mb per day). Source: IEA [8]. (Online version in colour.)

Crude oil production is heavily concentrated in a small number of countries and a small number of giant fields, with approximately 100 fields producing one half of global supply, 25 producing one quarter and a single field (Ghawar in Saudi Arabia) producing approximately 7% [5]. Most of these giant fields are relatively old, many are well past their peak of production [9], most of the rest seem likely to enter decline within the next decade or so and few new giant fields are expected to be found [4]. Future global production is therefore heavily dependent on the future prospects of the giant fields, but this remains uncertain—in part because the required field-level data are either unavailable or unreliable [4].6

(b) Oil reserves

The volumes of oil underground are variously described as reserves or resources depending upon how probable it is that these volumes will be produced over a given time frame with existing technologies. These volumes can be very different and must be clearly defined.

Oil reserves are those quantities of oil in known fields which are considered to be technically possible and economically feasible to extract under defined conditions. Reserve estimates rely upon uncertain assumptions about geology, technology and economics and are best expressed as a probability distribution. Point estimates may be quoted to three levels of confidence, namely proved (1P),proved and probable (2P) and proved, probable and possible (3P). While definitions vary, these are often considered equivalent to the probabilistic definitions P90, P50 and P10 which express the percentage probability that at least this quantity will be recovered [10]. Most data sources report proved reserves but these provide a highly conservative estimate of future recovery, especially at the regional level [11].7

Only a subset of global reserves is subject to formal reporting requirements and this is largely confined to the reporting of proved reserves for aggregate regions. Such data are notoriously unreliable, with many countries reporting unchanged reserves for decades (figure 5).8 Proved and probable (2P) estimates should provide a more accurate guide to future recovery, as well as posing fewer problems with aggregation, but these estimates are more difficult to obtain and are not necessarily more reliable.

Figure 5.

Annual proved reserves estimates for five Middle East states (1980–2011). Source: BP [13]. Saudi Arabia produced 100 Gb and the United Arab Emirates 27 Gb during this period. (Online version in colour.)

Globally, BP [13] estimates 1263 Gb of conventional proved reserves in 2011 (slightly more than cumulative production to date) and 389 Gb of non-conventional proved reserves. The latter comprise 169 Gb of Canadian oil sands and 220 Gb of Venezuelan extra-heavy oil, but both estimates are disputed and only a fraction of this volume is likely to be recovered over the next 25 years. In principle, global 2P reserves should be larger than 1P reserves, but according to an authoritative industry source (IHS Energy) global 2P reserves are approximately the same as national declared 1P reserves—suggesting an overstatement of proved reserves by several producing countries. Global proved reserves are rising, together with the global proved reserve to production (R/P) ratio (figure 6), suggesting to some that there is little risk of near-term supply constraints [15]. But proved reserves provide a misleading basis with which to measure depletion or forecast future production rates [16] and similar trends in R/P ratios have been observed in regions such as the UK where production has peaked and then declined [11].

Figure 6.

Global trends in all-oil proved reserves and the proved reserve to annual production ratio. Source: BP [13]. (Online version in colour.)

(c) Oil discoveries

The sum of cumulative production and reserves is commonly referred to ascumulative discoveries. At end 2011, both BP [13] and IHS Energy estimated global cumulative discoveries of conventional oil to be around 2486 Gb, although their reserve definitions and coverage of liquids do not coincide. Regional cumulative discovery estimates are changed by the discovery of new fields and by revisions to the reserve estimates for existing fields. The latter is commonly referred to as reserve growth, although cumulative discovery growth is a more accurate term, because high production rates may still cause the remaining reserves to fall year by year. Sources of reserve growth include better geological understanding, improved extraction technology, variations in economic conditions and changes in reporting practices.

The term discoveries may mean the resources contained in fields that are newly discovered within a particular time period or the change in cumulative discoveries from one period to the next. These are not necessarily the same, since reserve growth at existing fields contributes to ‘discoveries’ under the second definition even if no new fields are found. Some data sources (e.g. BP) record this reserve growth in the year in which the adjustments are made, while others (e.g. IHS) backdate the revisions to the year in which the relevant fields were discovered. Figure 7 (which uses backdated data) suggests that global new-field discoveries peaked in the 1960s and have fallen steadily since, although with an upturn around the turn of the century. Despite continuing improvements in exploration technology, most of the giant fields were discovered decades ago with more recent discoveries being smaller and more challenging to find and produce.

Figure 7.

Global trends in backdated discoveries and cumulative discoveries. Source: IHS Energy. Includes crude oil, condensate, NGL, liquefied petroleum gas, heavy oil and syncrude. Based upon backdated 2P reserve estimates. (Online version in colour.)

Figure 8 suggests that annual production has exceeded annual discoveries since 1980, but this conclusion neglects the contribution of reserve growth. The latter is hidden in figure 8 since the data source (IHS) backdates reserve revisions to the date of field discovery. When revisions are not backdated, annual reserve additions (i.e. the sum of newly discovered fields and reserve growth at existing fields) are found to exceed annual production, leading to an upward trend in global reserves (figure 6) [13,18]. Using industry 2P data, we estimate that approximately 48 Gb was added to global reserves each year between 2000 and 2007, split between approximately 15 Gb per year of new discoveries and approximately 33 Gb per year of reserve growth [11]. Reserve growth is therefore of considerable importance, but as production shifts towards newer, smaller and offshore fields the rate of reserve growth is expected to decrease in both percentage and absolute terms [1921].

Figure 8.

Global trends in production and backdated discoveries. Source: IHS Energy. Includes crude oil, condensate, NGLs, heavy oil and syncrude from oil sands. Discoveries based upon backdated 2P reserve estimates. While discoveries have fallen over time, the graph is potentially misleading since the discoveries for different years have not been estimated on a consistent basis. For example, the estimates for 1957 include 50 years of reserve growth, while the estimates for 2006 include only one year. This helps explain why comparable graphs published at different times have slightly different ‘heights’ and shapes for the backdated discovery data [17]. (Online version in colour.)

(d) Oil resources

The oil resource may refer to all the oil in an area, regardless of whether or not it is dispersed or accumulated, discovered or undiscovered, technically recoverable or economic to produce. Confusingly, the term sometimes refers solely to potentially recoverable oil. Estimates may be made of the technically recoverable resource (TRR) and/or the economically recoverable resource (ERR), but the range of uncertainty is usually very wide and these terms are often used interchangeably. The term ultimately recoverable resource (URR) refers to the oil that is estimated to be recoverable from a field or region over all time—from when production begins to when it finally ends.9

For conventional oil, the regional URR represents the sum of cumulative production, declared reserves, the anticipated reserve growth at known fields and the resources estimated to be recoverable from undiscovered fields—commonly termed the yet-to-find (YTF). The latter term is less appropriate for tight oil and oil sands, since these are located in continuous formations rather than discrete fields. However, extensive drilling is required to establish the spatial boundaries, geological characteristics and recoverable resources of these formations, and the productivity of individual wells varies widely both within and between such formations [2225].

Estimates of the global URR for conventional oil fall within the range 2000–4300 Gb, compared to cumulative production of 1248 Gb through to 2011 [11]. The IEA’s [8] most recent estimate is 3926 Gb which is higher than earlier estimates and reflects recent reassessments of the non-US YTF (731 Gb)10 and future reserve growth (681 Gb) [27,28]. Estimates of the URR of all-oil are much larger (e.g. 7119 Gb from the IEA [8]) and suggest that only one-sixth of the total recoverable resources has been produced (figure 9). However, the confidence intervals for such estimates are very wide [11,2729].

Figure 9.

IEA estimate of the remaining technically recoverable resource of all-oil. Source: IEA [8]. (Online version in colour.)

In interpreting these numbers, it is essential to recognize that large quantities of resources within the Earth’s crust provide no guarantee that these can be produced at particular rates and/or at reasonable cost. There are huge variations both within and between resource types in terms of size of accumulation, depth, accessibility, chemical composition, energy content, extraction cost, net energy yield (i.e. the energy obtained from the resource minus the energy required to find, extract and process it), local and global environmental impacts and, most importantly, the feasible rate of extraction—to say nothing of the geopolitics of access. Higher quality resources tend to be found and developed first, and as production shifts down the ‘resource pyramid’, increasing reliance must be placed upon less accessible, poorer quality and more expensive resources that have a progressively lower net energy yield and are increasingly difficult to produce at high rates. Compare, for example, the monetary and energy investment required to produce 100 kb per day from the giant oil fields of the Middle East to that required to achieve comparable rates of production from deep-water oil fields, subarctic resources or the Canadian oil sands. To quote a widely used phrase in this context, it is not so much the size of the tank that matters but the size of the tap.

This is not simply an issue of the steeply rising production costs of poorer quality resources because technical and net energy constraints may make some resources inaccessible and some production rates unachievable regardless of cost. Kerogen oil is especially constrained in rate and net energy terms and may never become economic to produce, yet it accounts for 19% of the IEA estimate of remaining recoverable resources (figure 9). Hence, a critical evaluation of future supply prospects must go beyond appraisals of aggregate resource size and examine the technical, economic and political feasibility of accessing different resources at different rates over different periods of time.

4. Oil ‘peaking’

The production of conventional oil must eventually decline to almost zero, because it is a finite resource. The phenomenon of ‘peak oil’ derives from basic physical features of the oil resource that constrain the ‘shape’ of the production cycle from an oil-producing region (i.e. the rate of production over time) and typically lead production to rise to a peak and then decline. But these physical features are mediated by multiple technical, economic and political factors that create a range of possibilities for the shape of the production cycle for a region and considerable uncertainty about the timing of any future peaks in production. The relative importance of these ‘below-ground’ and ‘above-ground’ factors varies between regions and over time and has become a central focus of dispute.

(a) Well and field peaking

As an oil well is brought online, its rate of production rises rapidly to a peak which may be extended into a plateau by restricting the flow rate or injecting fluids to maintain reservoir pressure. But at some point, production begins to decline as a result of falling pressure and/or the breakthrough of gas or water (figure 9). In mature wells, the ‘water-cut’ may represent 90% or more of the volume of produced liquids, creating a challenge for disposal. Production profiles of individual fields tend to be similar, with larger fields having longer plateaus achieved in part by drilling new wells.

Post-plateau, the production from individual wells and fields typically declines at a constant rate (exponential decline) or at a falling rate (hyperbolic decline). Empirical equations to model this production decline are widely used to forecast future well or field production and to estimate ultimate recovery [9,30,31]. In practice, the shape of the production cycle is often modified by production interruptions, the introduction of new technology and other factors.

For most oil fields, the decline period accounts for the majority of the production cycle and the bulk of cumulative production. As an illustration, figure 10 shows how each of the UK’s largest offshore fields (Forties, Brent and Ninian) took 3–8 years to reach peak, stayed on a plateau for 2–3 years and then entered a prolonged and approximately exponential decline. Forties produced 29% of its cumulative production to date before peak, Ninian 30% and Brent 40%. From a sample of 77 post-peak UK fields, we estimate an average decline rate of approximately 12.5% per year, and an average of 40% of cumulative production before peak—a number that will fall with time because the fields are still producing [4].

Figure 10.

Production profiles for three UK North Sea oil fields, with indicative exponential decline curves. Source: UK Department of Energy and Climate Change. (Online version in colour.)

To maintain or increase regional production, the declining production from post-peak fields needs to be replaced by increased production from new fields.11Hence, the average rate of decline from post-peak fields is a critical determinant of regional and global investment needs and future oil supply. Recent studies of globally representative samples of post-peak crude oil fields find a production-weighted average decline rate of at least 6.5% per year [5,32,33]. This is lower than the average decline rate, since larger fields tend to decline more slowly [4,3237]. Decline rates appear particularly low for the supergiant fields of the Middle East, but this is partly a consequence of quota restrictions of the Organization of the Petroleum Exporting Countries and disruptions from political conflict. The same studies also demonstrate that offshore fields decline faster than onshore fields and that newer fields decline faster than older fields [4]. If smaller, younger and offshore fields account for an increasing share of future global production, the average decline rate for conventional oil fields will increase prior to the peak [5].12 Greater reliance upon tight oil resources produced using hydraulic fracturing will exacerbate any rising trend in global average decline rates, since these wells have no plateau and decline extremely fast—for example, by 90% or more in the first 5 years (figure 11) [24]. The implications of this for global production are explored further below.

Figure 11.

Mean decline curve of tight oil wells in the Bakken play in North America. Source: Hughes [24]. Compiled from 66 months of production data from Bakken wells up to May 2012. The total number of wells climbed from approximately 20 in 2004 to 4598 in May 2012. The mean first year decline is 69% and the overall decline over five years is 94%. (Online version in colour.)

(b) Regional peaking

petroleum basin is a geologically defined region containing several fields, such as the North Sea. The shape of the basin production cycle depends upon the size distribution of the component fields, the order in which they are discovered and produced and the production cycle of each. Most oil resources in a basin tend to be located in a small number of large fields, with the balance being located in a much larger number of small fields [4,3941].13 The large fields tend to be discovered relatively early, in part because they occupy a larger area, with subsequent discoveries tending to be progressively smaller and requiring more effort to locate [11].

Despite varying political and economic influences on resource development, this broad pattern usually applies and has important implications that can be illustrated with the help of a simple model (figure 12). Here, it is assumed that one field is brought into production every year and each field is 10% smaller than its predecessor. In this example, the regional peak of production (in year nine) occurs when the additional production from the small fields that were developed relatively late becomes insufficient to compensate for the decline in production from the large fields that were developed relatively early. At this point, approximately one-third of the recoverable resources of the basin have been produced, half are contained in the reserves of producing and discovered fields, and one-fifth remain to be discovered.

Figure 12.

Simple model of the production cycle of a basin. Assume that (i) one field is brought on-stream each year in declining order of size; (ii) each field is 10% smaller than the previous field; (iii) fields take two years to reach peak, which is sustained for two years; (iv) peak production is 10% of URR annually; and (v) annual post-peak production is 13% of remaining resources, yielding a production decline rate of 13% per year. Source: based on Bentley et al. [42]. (Online version in colour.)

Models such as this are robust to a variety of assumptions about the size distribution, discovery sequence and production cycle of individual fields, providedit is assumed that the larger fields are found and developed relatively early [43]. Such models suggest that production from the basin will begin to decline when less than half of the regional URR has been produced, leading to an aggregate production cycle that is asymmetric to the left [11]. This is strongly supported by empirical evidence from the growing number of oil-producing regions that have passed their peak of production. For example, Brandt [44] analysed 74 post-peak regions and found that the rate of production increase exceeded the rate of decline in over 90% of cases. Similarly we analysed 37 post-peak countries and found an average of only 24% of the estimated URR had been produced at the onset of decline.14

The UK North Sea (figure 13) provides an excellent example of this process and is one of few where the relevant data are in the public domain. The first peak preceded the Piper Alpha disaster of 1988, which led to extensive remedial engineering and lower production in many fields, but the second was driven by the mechanisms described above. It may not be a coincidence that this peak occurred in 1999 when oil prices and exploratory drilling were at a 30-year low, but the small size of subsequent discoveries suggests that the peak could not have been significantly delayed—and in the absence of Piper Alpha may have occurred earlier.

Figure 13.

UK offshore oil production by field, 1975–2011. Source: data from UK Department of Energy and Climate Change. (Online version in colour.)

Oil-producing countries incorporate partial, single or multiple basins that are not necessarily developed in decreasing order of size. Nevertheless, country or regional production cycles are usually similar to those of individual basins.Figure 14 shows the aggregate production profile for the USA, broken down by region and oil type. The 1970 peak in Lower 48 production (9.6 mb per day) was anticipated by Hubbert [46] and largely driven by the declining size of newly discovered fields although state restrictions on production influenced the timing [47]. New plays in Alaska and the deep-water Gulf of Mexico temporarily increased aggregate US oil production in the late 1970s and mid-1980s, and the development of tight oil resources has done the same since 2008.

Figure 14.

US crude oil production by region and type, 1949–2011. Source: US Energy Information Adminis- tration (http://www.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb0501b;http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm); North Dakota Department of Mineral Resources (http://www.dmr.nd.gov/oilgas/stats/statisticsvw.asp); Texas Railroad Commission (http://www.rrc.state.tx.us/eagleford/index.php#stats). Bakken Formation tight oil production estimated by subtracting extrapolated conventional oil production from total production. (Online version in colour.)

The production cycle for tight oil resources is driven by a slightly different set of mechanisms since this resource is located in continuous formations rather than discrete fields. Nevertheless, the outcome is similar to that for conventional oil. With exceptionally high decline rates for individual wells (figure 11) regional tight oil production can only be maintained through the continuous drilling of closely spaced wells.15 But tight oil plays are heterogeneous, with much higher well productivity in the ‘sweet spots’ than elsewhere [2224,48]. So when the sweet spots become exhausted, it becomes increasingly difficult to maintain regional production. Based upon these considerations, Hughes [24] suggests that aggregate US tight oil production is likely to peak around 2.5 mb per day (compared to total US oil production of 6.9 mb per day in 2008) and is likely to decline very rapidly after 2017.16 Other, less detailed studies are more optimistic: for example, the IEA projects a peak of 3.2 mb per day in 2025, followed by a slower decline.

5. Oil futures

(a) Anticipating the global peak

The same mechanisms that lead to peaks and declines in regional oil production should ultimately lead to a peak and decline in global production. This inevitability was first pointed out by Hubbert in the mid-1950s, but the multiple forecasts of regional and global peaks that have been made since that date have frequently proved premature [49]. More optimistic forecasts have often proved equally incorrect, but it takes longer for their errors to become evident [50,51].

The available methods for forecasting future oil supply vary widely in their theoretical basis, inclusion of different variables, level of aggregation and complexity [11,52]. Each approach has strengths and weaknesses and none can yet provide generally accepted estimates (box 2).

Box 2.

Methods of forecasting oil supply.

Hubbert’s method involved fitting curves to historical trends in regional production and discovery and extrapolating these forward in time, constrained by assumptions about the size of recoverable resources. This ‘curve-fitting’ approach is straightforward and widely used, but lacks an adequate theoretical basis, relies upon uncertain assumptions about the regional URR, is sensitive to the choice of functional form and neglects important economic and political variables [53]. The latter may be more easily accommodated with econometric techniques [54,55], but while these provide a better match to historical data this may not translate to more accurate forecasts of future production. Hybrids of curve-fitting and econometrics offer promise, but can also have the disadvantages of both [56,57]. Systems dynamic models [58,59] reproduce the physical and economic mechanisms that govern oil production, but can also be overcomplicated and unstable and frequently lack both empirical validation and sufficient data for parametrization. Perhaps the most promising approach is to model the production of individual fields and projects and to construct regional forecasts by aggregating this bottom-up information [60]. However, existing bottom-up models are hampered by their reliance on proprietary datasets, lack of transparency, uncertainty over key variables and the need to make multiple assumptions [52]. Given the potential for political, economic, or technological disruptions, no model can provide estimates of great precision. Moreover, increasing model complexity does little to address this problem and is subject to rapidly diminishing returns.

But despite multiple uncertainties, the timing of the global peak in conventionaloil production appears relatively insensitive to both the size of recoverable resources and the shape of the production cycle [11,61]. Simple calculations suggest that delaying a global peak in conventional oil production beyond 2030 would require more than 1700 Gb of remaining recoverable resources (i.e. a URR>3000 Gb), together with a relatively slow increase in production prior to the peak and a relatively rapid decline thereafter, especially if the peak is extended into a multi-year plateau [11].

Following an earlier literature review, we concluded that a sustained decline in global conventional production appears probable before 2030 and there is significant risk of this beginning before 2020 [11,62]. This assessment excluded tight oil resources since these were classified as unconventional. However, on current evidence the inclusion of tight oil resources appears unlikely to significantly affect this conclusion, partly because the resource base appears relatively modest (figure 9). Despite rising proved reserves, the depletion of conventional oil resources is relatively advanced with cumulative production equal to at least 30% of the global URR (i.e. close to the point at which production has typically been found to decline in a region). A significant portion of this resource is located in small fields in difficult locations that are unlikely to be accessed quickly. However, global supply is profoundly influenced by geopolitical factors and any supply constraints are likely to trigger much greater price increases and demand/substitution responses than would be the case at the regional level—a process that is already underway. As a consequence, a sharp peak in global conventional oil production appears unlikely.

To maintain or increase global liquids supply, any decline in production from post-peak fields needs to be replaced by investment in EOR at those fields (at much greater than historic investment rates, the effects of which contribute to the current global post-peak decline rate), the discovery and development of new fields or increased production of other liquid fuels. Current evidence on average field decline rates suggests that a minimum of 3 mb per day of new capacity must be brought on stream each year to compensate for declining crude oil production—equivalent to a new Saudi Arabia coming on stream every three years [4,8]. If demand grows and/or decline rates increase, significantly greater annual investment will be required.

Based upon these considerations, the IEA [8] anticipates crude oil production from existing fields falling from 68.5 mb per day in 2011 to only 26 mb per day in 2035 (figure 15). However, it expects total crude production to fall only slightly by that date (to 65.4 mb per day) as a result of the rapid development of ‘fallow’17 and undiscovered crude oil fields. Moreover, it anticipates global all-liquids production increasing to 96.8 mb per day over that period as a result of rapid growth in NGL production and the development of tight oil, oil sands and other unconventional resources. In other words, while the IEA now suggests that global crude oil production is past its peak, it does not anticipate a significant decline before 2035 and it foresees no peak in conventionalall-oil orall-liquids production before that date.

Figure 15.

IEA projection of global all-liquids production to 2035. Source: IEA [8]. The ‘New Policies’ scenario takes into account policy commitments and plans that have already been implemented, as well as those that have been announced. (Online version in colour.)

Despite the projected global liquids supply up to 2035 being significantly lower than in earlier IEA publications, these projections remain the target of criticism. For example, Höök et al. [37] argue that production from existing fields could decline more quickly than the IEA assumes, while Aleklett et al. [63] argue that the projections rely upon implausible assumptions about the rate at which fallow and undiscovered fields can be developed and produced.18 Both studies imply more rapid decline of global crude oil production and hence more difficulty in maintaining aggregate global liquids supply. Furthermore, the IEA projection assumes adequate investment, no geopolitical interruptions and prices that do not significantly constrain global economic growth.

(b) Substitution and demand reduction

Given the multiple uncertainties involved, disputes over the precise timing of a global peak in conventional oil production are unhelpful. What is more relevant is the appropriate response to the risk of rising prices and supply constraints and the extent to which markets can be relied upon to mitigate those risks. Mitigation can be achieved through fuel substitution and demand reduction but both will prove challenging owing to the scale of investment required and the associated lead times. For example, a 2008 report for the US Department of Energy [64] argued that large-scale mitigation programmes need to be initiated at least 20 years before a global peak if serious shortfalls in liquid fuels supply are to be avoided. While this report overlooked key options such as electric vehicles and tight oil, it also assumed a relatively modest rate of post-peak crude oil decline (2% per year)19 and ignored the environmental consequences of expanding the supply of non-conventional resources. Avoiding these would necessarily restrict the range of available options.

Many sources anticipate large-scale substitution of NGLs for crude production over the next two decades, owing to expanding gas supply (including shale gas) and/or increases in the average NGL content of that gas. While the IEA [5] states that the latter is expected to remain constant, its projections imply a doubling. But even assuming production grows as anticipated, NGLs cannot fully substitute for crude oil since they contain about a third less energy per unit volume and only about one-third of that volume can be blended into transport fuels.20 NGLs can substitute for crude oil as a petrochemical feedstock and may partially compensate for increased heavy oil within the refinery input mix, but at some point a rising volume of NGLs will be unable to adequately make up for reduced crude supply.

The rapid and largely unexpected expansion of tight oil since 2007 provides a powerful demonstration of how technical change, incentivized by rising prices, can offset depletion. Heralded by some as a revolution [65], this resource is at an early stage of development and its future prospects remain highly uncertain. On current evidence, tight oil appears unlikely to offset the depletion of crude oil for an extended period of time, in part because the resource base appears relatively modest (figure 9). The IEA mean estimate of 240 Gb is comparable to McGlade’s [66] (278 Gb)21 and is only 10% of its estimate of conventional oil resources. Also, the very high decline rates make it challenging to sustain regional production, and the requirement for continuous drilling of closely spaced wells is likely to restrict development in densely populated areas. Nevertheless, the future potential of this resource is much debated and is a key area of uncertainty to resolve.

 Oil sands already make an important contribution to global liquids supply and most forecasts anticipate a significant expansion over the next 20 years. But according to the Canadian Association of Petroleum Producers [68], the Canadian oil sands will deliver only 5 mb per day by 2030, which represents less than 6% of the IEA projection of all-liquids production by that date. Similarly, Söderbergh et al. [69] conclude that a ‘crash programme’ to develop the oil sands could only deliver a comparable amount. Also, this resource is significantly more energy- and carbon-intensive than conventional oil, and surface mining has massive impacts on local and regional environments.

 GTLs and CTLs are already produced in small volumes as high cost alternatives to conventional oil and may be expected to expand their contribution in the future. But the environmental impacts of CTL production are severe and the inefficiencies of the process mean that significant quantities of coal and gas would be required to provide more than a marginal contribution to total liquids supply [70]. Taken together, these features are likely to greatly restrict their potential contribution.

Finally, biofuels offer promise as well as potentially lower environmental impacts, but expansion of production is constrained by the large land areas required22 and the probable conflicts with food production. Commercially produced biofuels also have a lower net energy yield than conventional oil, implying the need for a 50–600% increase in primary energy inputs to produce an equivalent volume of transportation fuels [72]. While several studies suggest that ‘second-generation’ biofuels could provide up to a quarter of global transport fuel by 2050 [73], these projections are sensitive to key assumptions [74] and would require significant technological breakthroughs.

Box 3

Oil and gas resources and cumulative carbon emissions. Source: [8,13,66,67].

A growing body of evidence indicates that global temperature change is approximately linearly related to cumulative carbon dioxide emissions and largely independent of the pattern of emissions over time [7882]. Several modelling studies suggest that the most probable cumulative emissions for an average global temperature increase of 2°C is around 1100 GtC, with a 5–95% uncertainty range of 1–2.5°C per 1000 GtC [80]. Given that humanity has already emitted some 550 GtC (to end 2011), a 50 : 50 chance of meeting the 2°C target is likely to require future cumulative emissions to remain below a similar value (approx. 550 GtC)—with a higher probability of meeting the target requiring lower emissions.

As the following figure indicates, such a threshold will be reached if the remaining recoverable resources (RRR) of conventional oil and gas are used, together with the proved reserves of oil sands and extra-heavy oil. Further exploitation of unconventional oil and gas resources would significantly reduce the probability of meeting the temperature target, unless those emissions can be captured and sequestered. However, this analysis ignores the emissions from coal combustion, which are currently 70% of those from oil and gas and are increasing more rapidly. As a result, the allowable ‘budget’ of oil and gas resources is much less than indicated here. Indeed, with a realistic allowance for future coal consumption, a 2°C target implies that only some of the conventional oil and gas resources can be used.

Graphic

These judgements deserve much closer scrutiny and need to be re-evaluated as experience grows in producing these resources. Based upon current evidence [8,70,73,7577], we estimate that around 11–15 mb per day of non-conventional liquids production could be achieved in the next 20 years at costs similar to or higher than today’s ‘marginal barrel’ at approximately $90–120 per barrel (figure 16). This would justify the IEA projection (figure 15), but only if crude oil production remains on a plateau over that period and NGL production expands as anticipated. If crude oil production falls, then total liquids production seems likely to fall as well, leading to significant price increases and potentially serious impacts on the global economy. Also, figure 15 obscures the falling energy content per unit volume of global liquids supply, together with the falling net energy yield and growing carbon intensity. The last point is especially serious, since ambitious targets for reducing carbon emissions are likely to be inconsistent with expanding the supply of non-conventional liquids. As box 3shows, avoiding dangerous climate change requires the bulk of these resources to remain in the ground.

Figure 16.

Estimated production cost of various oil resources. Source: IHS-CERA. Assumes 15% rate of return. Canadian oil sand production is relatively cheap at the mine mouth, but requires expensive upgrading before it can be transported by pipeline to refineries. Source: [8,13,66,67]. (Online version in colour.)

The final and most promising mitigation option is to weaken the link between economic growth and liquid fuel demand. This will require major changes in the transport sector which accounts for half of global consumption and nearly two-thirds of OECD consumption. Passenger cars are responsible for approximately half of this, but substantial reductions can be achieved through improving vehicle efficiency, increasing average occupancy, accelerating the diffusion of alternative vehicle technologies, shifting to different transport modes or simply reducing the overall demand for mobility. Given the potential of all these alternatives [83] and the necessity to move rapidly towards low carbon transport systems, they deserve to be given the highest priority. Important changes in this direction are already underway, such as the recent halting of the long-term trend of increased passenger travel in OECD countries (‘peak car’) [84], and the multiple policy initiatives being introduced around the world. But the core issue is the rate at which this transition can be achieved and the extent to which it can offset the rapidly growing and potentially huge demand for car-based mobility in emerging economies and the developing world. For example, with over one hundred million cars, China is now the largest car market in the world, but per capita levels of car ownership remain comparable to that in the USA in 1920.

As Sager et al. [85] have shown, OECD levels of car-based mobility are unlikely to be sustainable for a global population of 9 billion, even assuming a rapid, global transition to battery-electric vehicles and very low carbon electricity systems. Hence, technical improvements will need to be accompanied by serious efforts to restrict the overall growth in mobility and to promote the most efficient modes. This conclusion applies even more strongly to shipping, road freight and aviation which currently account for 40% of transport energy use and which have comparatively few technical solutions available. We therefore expect the combination of oil depletion and environmental constraints to have far-reaching implications for these modes, along with the economic activities and social practices they enable. But most governments and electorates remain either unaware of these implications or reluctant to face up to them.

6. An overview of the Theme Issue

As the above discussion demonstrates, future oil supply is a complex and multifaceted topic, with multiple influencing variables and varying opportunities for mitigation. To improve understanding of these issues, the papers in this Theme Issue of Philosophical Transactions A seek to provide an up-to-date synthesis of the uncertainties and risks surrounding future global oil supply, as well as assessing the potential of several mitigation options. The papers include perspectives from both the natural and social sciences and reflect a range of views.

The first five papers examine a number of aspects of conventional oil depletion. In the first, Sorrell & Speirs [86] examine the use of curve-fitting techniques for estimating recoverable resources—an approach closely associated with the peak oil debate. They summarize the historical origins, contemporary application and strengths and weaknesses of nine different types of curve-fitting technique, and update and extend Hubbert’s mathematical synthesis of those techniques [87,88]. Using illustrative data from a number of oil-producing regions, they demonstrate how different techniques, together with variations in the length of time series, functional form and number of curves, repeatedly lead to inconsistent results. They conclude that such techniques have a systematic tendency to underestimate recoverable resources and hence raise concerns about their use in forecasting future oil supply.

 Höök et al. [89] summarize the current state of knowledge on the rate of decline of production from different types of crude oil fields (decline rates) and the rate at which remaining resources are being and can be produced (depletion rates). They clarify the definition of decline and depletion rates, identify their physical and economic determinants, explain their importance for regional and global oil supply and examine how these rates vary between different regions and types of field. They conclude that decline and depletion rates are generally higher for smaller fields and question the values that are assumed or implied for these variables within several global supply forecasts.

 Murphy [90] examines the importance of the energy return on investment(EROI) for liquid fuels production and the implications of declining EROI for the global economy. From a review of the rather limited literature on this topic, Murphy concludes that: the EROI for global oil and gas production is roughly 15 and declining while that for the USA is 11 and declining; the EROI for unconventional oil and biofuels is generally less than 10; there is a negative exponential relationship between oil prices and aggregate EROI which may become nonlinear as the latter falls below 10; and the minimum oil price needed to increase oil supply is consistent with that which has historically triggered economic recessions. Murphy concludes that the declining EROI of liquid fuels will make it increasingly difficult to sustain global economic growth.

 Jackson & Smith [38] provide an optimistic view of global oil supply, based in part upon industry data on the production from individual fields and assumptions about the contribution of new technology and tight oil. They emphasize the economic and political factors influencing long-term supply and argue that resource depletion will not provide a significant constraint for at least two or three decades. Instead, they anticipate significantly lower rates of demand growth contributing to an initial ‘undulating plateau’ and subsequent slow decline of both conventional and all-oil production sometime after 2040. They anticipate a steady increase in upstream investment requirements and oil price volatility, leading to fuel substitution and improved energy efficiency.

 Kumhof & Muir [91] use the International Monetary Fund’s Global Integrated Monetary and Fiscal Model to assess the implications of oil supply constraints for the global economy. They initially assume that oil demand and supply are unresponsive to price changes and find that a small reduction in the growth rate of world oil production has only modest effects on gross domestic product. They then investigate three alternative scenarios in which: (i) there is less scope for substitution between oil and other energy resources; (ii) the contribution of oil to economic output is higher than conventionally assumed; and (iii) the reduction in global oil production is larger. Each scenario alone, but especially in combination, leads to a significant reduction in economic activity. Kumhof and Muir highlight the competing views about the plausibility of these alternative scenarios, the potential for nonlinear responses and the risk of greater impacts from oil depletion than orthodox economic theory suggests.

The remaining six papers investigate the potential of various mitigation options. In the first, Muggeridge et al. [6] provide a comprehensive overview of the nature, status and prospects for EOR techniques and their potential contribution to global oil supply. They begin by introducing the oil field recovery equation, summarizing the evidence on global recovery rates and explaining why these are typically low. They then examine the nature of EOR processes, the history of their application and the current status and contribution of EOR worldwide. They describe two, new, broadly applicable, low cost EOR technologies and give examples of existing and new EOR projects in different regions of the world. They conclude by highlighting the synergy between CO2 sequestration and EOR, the further technical advances that may be expected and the need to accelerate global deployment.

 Chew [92] describes the nature, extent and characteristics of ‘unconventional’ oil and gas resources. He reviews the extraction technologies and provides a detailed assessment of the size and recoverability of each resource. Chew finds that oil sands, extra-heavy oil and kerogen oil have large in-place resources, large areal extent, low exploration risk and the potential for long, stable production life. However, their low recovery factors, high cost, capital and energy intensity and long lead times make them only a partial substitute for conventional oil. Tight oil presents fewer recovery problems, but the resource base is modest. In contrast, unconventional gas resources appear significantly larger than those of unconventional liquids and continued growth in unconventional gas production could have significant impacts on the global oil market.

 Höök et al. [70] provide an overview of CTL and GTL technologies, including their chemistry, technology, process efficiencies, input requirements, economics and environmental impacts. They argue that economic analyses have tended to underestimate costs and that a significant and locally concentrated amount of coal and gas would be required for these technologies to provide more than a marginal contribution to liquid fuel supply. Moreover, CTL and GTL production has significant environmental impacts which could slow or even stop their development unless adequate solutions can be found.

 Timilsina [73] examines the potential contribution of biofuels to the global energy mix. Concern over the impact of biofuels on food prices has led several countries to reduce policy support, thereby slowing down the rate of production growth and increasing interest in second generation feedstocks. Given their relatively high costs, Timilsina estimates that biofuels are unlikely to contribute more than 5% of global transport fuel demand over the next 10–15 years. Projections of biofuels contributing one quarter of transport fuel demand by 2050 appear optimistic and would require significant technological breakthroughs. The contribution of biofuels to greenhouse gas emission reduction is also undermined by their indirect impacts on land use change.

 Delucchi et al. [93] evaluate the status and prospects of electric vehicles (EVs) as a mitigation option. They begin by describing the technical features of battery, fuel cell and plug-in hybrid technology and their current state of development. They then examine the key technical challenges, including the cost, performance and lifetime of batteries and fuel cells, and the energy use, driving range, power and recharging time of different types of vehicle. They demonstrate the significant environmental benefits of EVs, argue that their lifetime cost can become comparable to that of conventional vehicles and suggest that problems of material scarcity can be overcome. Large-scale deployment hinges upon infrastructure development—including battery charging options and integration with low carbon electricity systems—and requires policies that bolster emerging markets, facilitate EV ownership and boost consumer confidence.

The final paper by Freedman [94] investigates the market and contextual factors influencing the uptake of EVs. The implementation of these technologies at scale requires careful attention to consumer-behavioural and policy challenges as well as adapting existing value chains and introducing new ones. The legacy of diverse urban planning and fuel taxation policies and varying degrees of consumer inertia will lead to very different rates of adoption in regional markets. In the absence of technology that provides a compelling consumer proposition, substitution of oil demand in OECD markets will be challenging, as will channelling exponential growth from the growing Asian market into less oil-intensive road transport solutions.

In combination, the papers provide a sobering picture of the challenges ahead. Most authors accept that conventional oil resources are at an advanced stage of depletion and that liquid fuels will become more expensive and increasingly scarce. The tight oil ‘revolution’ has provided some short-term relief, but seems unlikely to make a significant difference in the longer term. Even with a more sanguine view of global supply prospects, the large scale, capital intensity, long lead times and constrained potential of the various mitigation options point to the need for a coordinated response.

At present, rising oil prices are incentivizing the development of supply-side options whose large-scale pursuit would guarantee dangerous climate change (box 3). Avoiding this outcome requires instead the prioritizing of demand-side options and far-reaching changes in global transport systems. Climate-friendly solutions to ‘peak oil’ are available, but they will not be easy, they will not be quick and they appear unlikely to allow the majority of the world’s population to achieve the levels of mobility currently enjoyed in the West. Lower mobility, in turn, implies a very different direction for future economic development. In sum, adapting rapidly and peacefully to oil scarcity in a manner that does not destroy the global environment provides humanity with a formidable challenge.

Acknowledgements

We are grateful to Peter Jackson, Ann Muggeridge and anonymous reviewers for most helpful comments on earlier drafts. We are also grateful to IHS Inc. for the data in figures 378 and 16. The use of such content was authorized in advance by IHS. Any further use or redistribution of this content is strictly prohibited without written permission by IHS Inc. who reserve all rights.

Footnotes

  • One contribution of 13 to a Theme Issue ‘The future of oil supply’.

  • 1 Alternative, non-biological (‘abiogenic’) origins for petroleum have also been proposed. These require a deep-Earth source of primordial methane which is converted, by Fischer–Tropsch reactions, into longer chain alkanes and other molecules, either in the upper mantle (the so-called Russian theory) or in the upper crust (the so-called Thomas Gold theory). These theories have been generally discredited, both on chemical and thermodynamic grounds and from considerable empirical evidence, such as the presence of biomarker molecules in oil that are directly traceable to biological precursors [2].

  • 2 Oil production and resources are commonly measured in volumetric terms, despite significant variations in specific gravity and energy content. One barrel (b) is approximately 158 litres and may weigh between 0.12 and 0.16 tonnes. Commonly used multiples include thousand (kb), million (mb) and billion barrels (Gb). A ‘barrel of oil equivalent’ (boe) is a quantity of fuel containing the average thermal energy of a barrel of oil, defined as 6.1 GJ (higher heating value).

  • 3 API gravity is defined as (141.5/specific gravity) – 131.5. API gravity therefore rises as the specific gravity falls.

  • 4 Water at a temperature of 21°C has a viscosity of approximately one centipoise.

  • 5 For brevity, the phrase ‘crude oil’ will be used in place of ‘crude oil and condensate’ in the remainder of this paper. This is because most data sources do not allow the produced volumes of these two liquids to be distinguished.

  • 6 Some field-level data are published annually by oil industry journals. More comprehensive data may be purchased (at considerable cost) from commercial sources, but there are questions over the reliability of some of these data, only a portion of which is audited.

  • 7 Regional reserve estimates are commonly derived by summing the estimates of individual fields, but such aggregation is only appropriate for mean estimates of recoverable resources and will lead to significant underestimation when applied to 1P (P90) estimates [11,12]. Aggregation of 2P (P50) estimates should lead to smaller errors, but the sign and magnitude of these will depend upon the shape of the underlying probability distribution.

  • 8 For example, the Oil and Gas Jounal[14] reports identical reserves estimates for 2010 and 2011 from 69 of 101 oil-producing countries.

  • 9 In principle, this includes oil that is currently undiscovered, not recoverable with existing technology and/or not currently economic, but which is expected to become so before production ceases.

  • 10 This estimate includes resources that are unlikely to be recoverable within the next 25 years, such as 74 Gb in the Arctic and FSU, but also excludes a number of smaller, less accessible regions that may potentially contain oil [26].

  • 11 Historically, EOR has only briefly been able to reverse the decline of any post-peak conventional field, and we see no reason for this behaviour to change. The effects of EOR are already included in contemporary estimates of the average rate of production decline from different groups of fields.

  • 12 In the long term, when global conventional production is past peak and the rate and size of discovery are falling, the old giant fields may increasingly dominate total production. If this occurs, the long term aggregate decline rate would converge towards the average decline rate of the giant fields [38].

  • 13 There is a long-standing debate about whether oil fields typically follow a lognormal or power-law size distribution [4]. But the uncertainties largely relate to the ‘tail’ of the distribution and do not affect this general conclusion.

  • 14 Using US Geological Survey [45] estimates of the regional URR, we estimated a simple mean for ‘depletion at peak’ of 22%, a production-weighted mean of 24% and a maximum of 52%. URR estimates tend to increase over time as knowledge expands, prices increase and technology improves, so estimates of the level of depletion at peak are likely to fall.

  • 15 The largest tight oil play in the USA is the Bakken in North Dakota. In May 2012, this was producing 0.57 mb per day from 4598 wells. Production was on a rising trend, sustained by drilling approximately 1500 wells each year. The US Energy Information Administration (EIA) estimates that there are only approximately 11 700 available drilling locations in the Bakken, although industry estimates are higher [24].

  • 16 Hughes’ [24] analysis is based upon the production history of 65 000 wells from 31 shale plays, contained in the DI Desktop/HDPI database, together with EIA data on the number of available drilling locations within each play. Assuming current drilling rates are maintained, Hughes projects a peak in US tight oil production of 2.3 mb per day in 2016, declining rapidly to 0.7 mb per day in 2025.

  • 17 Fallow fields are fields that are discovered but not currently scheduled for development.

  • 18 Aleklett et al. estimate historical depletion rates for different regions, defined as the ratio of annual production to remaining recoverable resources, together with the depletion rates assumed by the IEA for fallow and undiscovered fields. This leads them to conclude that the depletion rates assumed by the IEA are implausibly large. But their comparison of regional depletion rates with the corresponding rates for specific groups of fields is potentially flawed.

  • 19 To frame this, a 2% decline in crude oil production implies the loss of 1.4 mb per day in the first year. On an energy equivalent basis, this corresponds to the output of ninety 1 GW nuclear power stations, or approximately one quarter of global nuclear capacity.

  • 20 Natural gasoline (pentane and above), isobutane and butane are conventionally blended into gasoline, but ethane and propane are not.

  • 21 Tight oil resources have not been systematically investigated on a global scale. McGlade [66] uses a relatively crude method based upon a review of shale gas resource estimates [67] and assumptions about the ratio of tight oil to shale gas within each region. This gives a range from 150 Gb to 508 Gb, with a central estimate of 278 Gb.

  • 22 For example, replacing US gasoline consumption with corn-based ethanol would require approximately two million km2 of cropland, which is 15% larger than the total US farmland area. Moreover, this calculation neglects the primary energy required to produce, transport, process and deliver the ethanol which appears to be only slightly less than the energy obtained from using it [71]. Hence, corn-based ethanol production is heavily subsidized in energy (as well as monetary) terms, making large-scale substitution impractical over the longer term.

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The 4 Big Dangers of Fracking

The 4 Big Dangers of Fracking.

By now you’ve likely heard that the U.S. is expected to overtake Russia this year as the world’s biggest producer of oil and gas. The surge in production comes from a drilling boom enabled by using hydraulic fracturing, or fracking, along with, in many places, horizontal drilling. These technologies have made previously inaccessible pockets of oil and gas in shale formations profitable.

But at what cost? Accidents, fatalities and health concerns are mounting. Here’s a look at what we’ve learned about the dangers of fracking in the last few weeks.

1. Exploding Trains

Another day, another oil train accident, it seems. On the night of January 7, a traincarrying crude oil and propane derailed near Plaster Rock in New Brunswick, Canada. A day later the fire continued as locals evacuated, unsure if they were being exposed to toxic fumes.

It’s a familiar story. 2013 went out with a bang in North Dakota when a train carrying crude oil from the Bakken shale derailed and exploded on Dec 30. The ensuing fireballs and toxic smoke caused the evacuation many of Casselton’s 2,300 residents.

Fracking has unleashed a firestorm of drilling in the Bakken (a rock formation under parts of North Dakota, Montana and Saskatchewan). The Casselton accident was the third rail accident in six months in North America involving oil trains from the Bakken (it’s unclear if the Plaster Rock train was carrying Bakken oil). The most horrific was the July derailment and explosion of a train that killed 47 people in the small town of Lac-Megantic in Quebec. The second occurred in Alabama in November.

All of this has grabbed the attention of the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration. “Crude oil produced in North America’s booming Bakken region may be more flammable and therefore more dangerous to ship by rail than crude from other areas, a U.S. regulator said after studying the question for four months,” wrote Angela Greiling Keane and Mark Drajem for Bloomberg.

That doesn’t mean shipments will stop, only that trains may be relabeled to say they are carrying a more hazardous cargo.

As Gordon Hoekstra wrote for the Vancouver Sun:

The significant increase in the transport of oil by rail, and the growing evidence that Bakken shale oil is proving itself to be a very explosive commodity, shows that regulations on both sides of the border are not adequate, said Mark Winfield, an associate professor at York University who researches public safety regulation.

Even Robert Harms, who heads North Dakota’s Republican party and consults with the industry, has called for a slowdown, according to Reuters.

2. Workers at Risk

Those who live along train routes aren’t the only ones facing safety risks from the oil and gas industry. NPR reports that accidents among workers in the industry are on the rise—bigtime. From 2009 to 2012 the industry added 23 percent more workers but “the hiring spree has come with a terrible price: Last year, 138 workers were killed on the job — an increase of more than 100 percent since 2009,” wrote Andrew Schneider and Marilyn Geewax for NPR . “In fact, the fatality rate among oil and gas workers is now nearly eight times higher than the all-industry rate of 3.2 deaths for every 100,000 workers.”

Last July, I visited a well pad in New Milton, West Virginia. The following day there was an explosion at the site injuring several workers, two of whom died from their injuries. In my time in West Virginia I met several workers on other sites who were bleary-eyed from long hours on the job.

Sure, jobs are good, but safe jobs should be a priority. Accidents happen in a dangerous industry, but they also increase when workers are kept on the job for too many hours or lack proper training or industry doesn’t follow safe practices.

3. The Accidents You Don’t Hear About

Trains bursting into flames usually (and rightfully) makes the national headlines—especially when fatalities occur. But smaller accidents happen daily that often fail to make it beyond local reporting, if that. Those who live in communities adjacent to the oilfields and gaslands keep their own tallies.

In Tyler County, West Virginia on January 2 an incident occurred on the Lisby natural gas well pad. The West Virginia Department of Environmental Protection press release said, “A tank ruptured and leaked fluids to surrounding grounds on the well site.”

“Ruptured and leaked” may be accurate, but more than an understatement. A tank filled with fracking fluid (although the WVDEP hasn’t been able to say for sure what exactly was in it) ignited and ended up across the well pad. “What we’ve been able to determine is that a tank ruptured during the flushing of frac lines,” said Thomas Aluise, spokesperson for the WVDEP. “Vapors formed from the fluids inside the tank and were somehow ignited, possibly by static electricity, but that has not been confirmed. As a result of the ignition and subsequent rupture, the tank was dislodged from its foundation.”

Does this photo look like the tank simply “dislodged?”

 

The tank held 50 barrels of fluid, some of which has leaked into soil, a neighboring property, and potentially into a nearby stream. The explosion happened 625 feet from the nearest house and one person at the site, a contractor who broke his ankle, was injured in the incident. The company, Jay-Bee Oil & Gas, is required to submit plans for soil and water sampling by January 14, which seems like quite a while to wait to take samples if chemicals are leaking into the ground or water sources.

Jay-Bee does not have a glowing corporate record. “The West Virginia Department of Environmental Protection has cited the company for 21 environmental violations since 2010, and the federal Occupation Safety and Health Administration has cited the company for 38 worker safety violations, “ wrote Gayathri Vaidyanathan for E&E. “The incident suggests that environmental and worker safety violations often go hand in hand.”

How many environmental and safety violations does it take before a company is shut down?

Accidents like this are common across oil and gas country. So are compressor station fires in PennsylvaniaNew YorkNew JerseyWyoming. Or truck accidents, as Food and Water Watch reports: “Heavy-truck crashes rose 7.2 percent in heavily fracked rural Pennsylvania counties (with at least one well for every 15 square miles) but fell 12.4 in unfracked rural counties after fracking began in 2005.”

The Centers for Disease Control reported that the top cause of fatalities in the oil and gas industry are motor vehicle accidents. “[W]orkers drive long distances on rural highways to travel to well sites. Often these roads lack firm shoulders and other safety features,” the agency reports. This puts not just workers at risk, but everyone on the road.

All these incidences won’t make national news, but collectively they add up for the residents who live nearby who may fear for their safety while on the roads or in their own homes.

4. Not So Good for Your Health

Findings presented at a recent meeting of the American Economic Association by researchers from Princeton University, Columbia University and Massachusetts Institute of Technology have made headlines. The researchers “looked at Pennsylvania birth records from 2004 to 2011 to assess the health of infants born within a 2.5-kilometer radius of natural-gas fracking sites,” reports Mark Whitehouse for Bloomberg.

“They found that proximity to fracking increased the likelihood of low birth weight by more than half, from about 5.6 percent to more than 9 percent,” writesWhitehouse. “The chances of a low Apgar score, a summary measure of the health of newborn children, roughly doubled, to more than 5 percent.”

The study has yet to be peer-reviewed, so let’s see how it fares. It does not implicate drinking water, however. The most likely culprit is air pollution. Oil and gas operations have been found to release volatile organic compounds (VOCs) and nitrogen oxides, which contribute to ground-level ozone.

So far no communities where fracking is occurring have done a comprehensive health assessment to see how residents may be at risk from activities related to increased oil and gas drilling. Is it time yet?

EIA International Energy Statistics for August and September » Peak Oil BarrelPeak Oil Barrel

EIA International Energy Statistics for August and September » Peak Oil BarrelPeak Oil Barrel.

The EIA has finally published its International Energy Statistics. The last one had July data. This one is has two months updates, August and September. All the data I publish comes is Crude+Condensate from January 2000 through September 2013.

Again, all data is C+C in thousand barrels per day with the last data point September 2013.

World

As you can see from the chart World C+C production has leveled out in the last year and one half. September 2013 is slightly lower than February 2012.

There were a couple of major revisions in the July data. Canada was revised down by 269 kb/d while Non-OPEC was revised down by 228 kb/d. There were other small revisions upward. OPEC C+C had no revisions so that left World C+C for July revised down by 228 kb/d.

Both the USA and Canada are on a real tear, owing of course to Light Tight Oil and the Oil Sands. Their combined production is up about 1.9 mb/d since in one year, since last September.

USA + Canada

But they are the only ones on a tear. Almost everyone else is flat to down with a few small producers up slightly.

World Les US & Canada

World less USA and Canada is actually below where it was in June 2004 and is swiftly approaching the bottom it hit after the crash of 2008. The peak was in January 11 and they are down 2.65 mb/d since that point.

Actually only Light Tight Oil is keeping the world from declaring peak.

World Less USA

World less USA is down over 1.5 mb/d since the peak of January 2011.

Non-OPEC is up on the strength of the USA and Canada.

Non-OPEC

However the EIA has OPEC C+C down considerably.

OPEC C+C

Charts of all Non-OPEC producers are now up on the Non-OPEC Chartspage.

Also a new page has been added, World Crude Oil Production by Geographical Area

Fears of global oil crisis aired at Transatlantic Energy Security Dialogue. : Jeremy Leggett’s Triple Crunch Log

Fears of global oil crisis aired at Transatlantic Energy Security Dialogue. : Jeremy Leggett’s Triple Crunch Log.

Jeremy Leggett column in Recharge magazine: “We are betting our entire national economic life on the hope — indeed the expectation — that the fracking boom will continue until well into the 2020s, and that, at a rate and cost we desire, significant amounts of ‘yet to be discovered’ oil will somehow be found to meet the demand.”
“If any of that proves incorrect, we have no plan, no alternative, and have given no thought to how we would respond in such a case.”The speaker is national-security expert Lieutenant Colonel Daniel Davis, a veteran of four tours of duty with the US Army in Iraq and Afghanistan. I am not a military man, but I worry just as much about the energy security of my own country as he does about his. In the UK, the government, the civil service and most of the big energy companies seem perfectly content to replicate the grand gamble under way in the US.
On 10 December, Lt Col Davis and I convened video-linked gatherings in Washington and London of people who share our concerns about the risk of a global oil crisis. We also invited key people who don’t, but who were interested in probing beyond the propaganda that energy-policy discourse seems to attract these days. [Two powerpoints, and Agenda  / Participants / Transcript of first half are appended below.]
Those joining us included retired military officers, security experts, senior executives from a wide spectrum of industry and politicians of all the main parties, including two former UK ministers.
We began with a presentation by Mark Lewis, a former head of energy research at Deutsche Bank. With this background, you might expect Lewis to be a disciple of the conventional narrative of plenty in oil markets. Many of his peers are. But he suggested that three big warning signs in the oil industry point to a counter-narrative of impending problems for supply: high decline rates, soaring capital expenditure and falling exports.
The decline rates of all conventional crude-oil fields producing today are spectacular; the International Energy Agency projects output falling from 69 million barrels per day (bpd) today to just 28 million bpd in 2035. Current total global production of all types of oil is some 91 million bpd.
Consider the spending needed to try to fill that gap.
Capex for oilfield development and exploration has nearly trebled in real terms since 2000: from $250bn to $700bn in 2012. The industry is spending ever more to prop up production, and its profitability is reflecting this trend, notwithstanding an enduringly high oil price. Meanwhile, consumption is soaring in Opec nations. As a result, global crude-oil exports have been declining since 2005. It is difficult to conflate this data and not see an oil crunch ahead, Lewis concludes.
What of the recent addition of two million bpd of new oil production from American shale: the boom that has even been cast as a “game-changer” and a route to “Saudi America” by industry cheerleaders?
Geological Survey of Canada veteran David Hughes, who has conducted the most detailed analysis of North American shale of anyone outside the oil and gas companies, offered some sobering views on this. His data shows that spectacularly high early decline rates in existing shale gas and shale oil (more correctly known as tight oil) wells means high levels of drilling are needed just to maintain production. This problem is compounded because “sweet spots” become exhausted early in field development.
As a result, shale-gas production is already dropping in several key drilling regions, and production of tight oil in the top two regions is likely to peak as early as 2016 or 2017. These two regions, in Texas and North Dakota, comprise 74% of total US tight-oil production.
Like Lewis, Hughes believes that the oil and gas industry is leading the world by the nose towards an energy crisis.
In my book The Energy of Nations, I describe how military think-tanks have tended to side with those, like Lewis and Hughes, who distrust the cornucopian narrative of the oil incumbency. One 2008 study, by the German army, puts it thus: “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 blanking-out extends to the mainstream media, which has enthusiastically echoed the mantras of the oil companies, to the extent that the very words “peak oil” have been positioned as a badge of baseless scaremongering.
We should never forget that in the run-up to the credit crunch, the financial incumbency deployed exactly the same PR tactics against those warning about the fragility of mortgage-backed securities.

Transatlantic Energy Security Dialogue: Agenda, Participants, Part One discussion edited transcript

The Three Witches: Decline rates, soaring capex, and falling exports. Presentation by Mark Lewis.

The “Shale Revolution”: Myths and Realities. Presentation by David Hughes.

Will US Light Tight Oil Save The World? » Peak Oil BarrelPeak Oil Barrel

Will US Light Tight Oil Save The World? » Peak Oil BarrelPeak Oil Barrel.

There has been plenty of hoopla lately concerning the boom in shale (LTO) oil production. From the New York Times: Surge Seen in U.S. Oil Output, Lowering Gasoline Prices

Domestic oil production will continue to soar for years to come, the Energy Department predicted on Monday, scaling to levels not seen in nearly half a century by 2016.

The annual outlook by the department’s Energy Information Administration was cited by experts as confirmation that the United States was well on its way — far faster than anticipated even a year ago — to achieving virtual energy independence.

What the EIA is actually predicting:  AEO2014 EARLY RELEASE OVERVIEW. The data is C+C.

AEO 2014

The first two points were what was actually produced in 2011 and 2012 and the rest of the blue line is what they are predicting for the future. The orange line is what they predicted last year. The predicted numbers this year are a lot higher but the shape of the curve looks the same. They predict US Crude + Condensate will plateau in 2016, actually peak in 2019 and by 2021 be headed for a permanent decline.

Note the difference between AEO 2013 and AEO 2014. The difference rises to just over 2 mb/d and holds that difference util 2030 when it slowly closes down to 1.37 mb/d in 2040. And everything above about 5 mb/d is all Shale, or Light Tight Oil. They expect LTO to rise to about 4.5 mb/d by 2016, hold that level for almost 5 years and for LTO to still be above 2.5 mb/d by 2040. 

Anyway here is what Saudi Arabia thinks about it all. Saudi will not be affected by shale oil output: report:

“Since we doubt that tight oil production will grow as much as most commentators surmise, and since we believe that tight oil production will keep representing only about 3% of total liquids supply, we do not believe that the growth in oil production from tight rock formations in the US, or from shale formations elsewhere, will materially affect Saudi Arabia’s long-term position in the oil industry,” Jadwa said in a study.

And questions are being raised elsewhere: Shale well depletion raises questions over US oil boom

In October, the government began issuing a monthly report on drilling productivity that charted declines in six major U.S. shale plays. The U.S. Energy Information Administration estimates that it takes seven of every 10 new barrels produced in those areas just to replace lost production.

Of course this article is quoting the EIA and their new Drilling Productivity Report.

Speaking of that report, Steve’s blog, SRSrocco Report, has this headline: Eagle Ford Shale Decline Shoots Up A Stunning 10% in One Month!

What Steve is talking about is this. First from last month’s Drilling Productivity Report:

Eagle Ford Dec

And see the difference from the latest report:

Eagle Ford Jan

But getting back to the statement in the “Fuel Fix” article that it takes seven of every 10 new barrels produced in those areas just to replace lost production. If the EIA is correct in their latest report it takes a bit more than 7 of every 10 barrels just to make up for the declines of old wells. If their figures are correct, in Eagle Ford, it takes almost 7.6 barrels of every 10 barrels from new wells just to make up for the decline in production from old wells. And of course that number increases every month.

If the EIA’s decline rates are anywhere close then the Bakken should reach her peak at about 1.25 mb/d and Eagle Ford at about 1.6 mb/d, or at some point very close to those numbers.

Bottom line, all the hype is just hype. The US will likely never reach 4.5 million barrels per day of shale oil, the peak will not be spread out over five years as the EIA believes, and the decline will be a whole lot steeper than the chart above indicates. Shale oil may delay the peak of world oil production for one year, or two at the most.

While it is true that only the Light Tight Oil is keeping Peak Oil from being an obvious fact, that can only last for a year or two, then the US, along with almost every other nation in the world will be in decline.

The EIA’s International Energy Statistics is about a month late already. International oil production data is a really low priority with the EIA. They are much more concerned with the price of kerosene and other such matters than they are with world crude oil, the lifeblood of every economy in the world. So we will have to do without it until they get around to posting that data, if ever. But in the meantime I have constructed the below chart using mostly JODI data, with some EIA data used for countries that do not report to Jodi. I use it just to show what the world oil supply would look like without US Light Tight Oil. The last data point is October 2013.

Jodi World Less USA

According to JODI, the world less USA peaked in January of 2008 and almost reached that point again in July of 2008. In October of 2013 we are down about 2.25 mb/d from that point. Interesting to note also that the world less USA has dropped some 1.5 mb/d since July. July was the last month the EIA’s International Data Statistics has data for.

Euan Mearns, below, asks that this chart be posted. The last data point is October 2013:

World Les US & Canada

It doesn’t look a lot different from the “World Less USA” chart. Down 2.53 Megabytes a day from the peak of July 2006. Keep in mind this is JODI data which differs somewhat from the EIA data. The EIA however only has updates through July 2013. There has been considerable attrition in production since then.

The following charts are based on data from the EIA’s AEO 2014 Early release.

aeo2014uscc1/
aeo2014uslto/

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peak oil climate and sustainability: When will US LTO(light tight oil) Peak?

peak oil climate and sustainability: When will US LTO(light tight oil) Peak?.

The rapid rise in oil output since 2008 has the mainstream media claiming that the US will soon be energy independent.  US Crude oil output has increased about 2.8 MMb/d (56%) since 2008 and about 2 MMb/d is from the shale plays in North Dakota ( Bakken/Three Forks) and Texas (Eagle Ford). My modeling suggests that a peak from these two plays may be reached by 2016, other shale plays (also known as light tight oil [LTO] plays) may be able to fill the gap left by declining Bakken and Eagle Ford output until 2020, beyond that point we will see a rapid decline.

US Light Tight Oil to 2040

fig 1

There are two main views:

  1. There will be little crude plus condensate (C+C) output from any plays except the Bakken/Three Forks in North Dakota and Montana and the Eagle Ford of Texas.
  2. The other LTO plays will come to the rescue when the Bakken and Eagle Ford reach their peak and keep LTO near these peak levels to about 2020 with a slow decline in output out to 2040.
Where are these “other LTO plays”?  There are a couple of these in Oklahoma and Texas (in the Permian basin, Granite Wash, Mississippian basin), the Appalachian, the Niobrara in Colorado, and others (see slide 17 of the USGS presentation link below).  Is it possible for these LTO plays to offset future declines in the Bakken and Eagle Ford?  I hope to answer that in this post.
When doing my modeling of the Eagle Ford, I needed an estimate of the technically recoverable resource(TRR) for that play.  The April 2013 USGS Bakken Three Forks Assessment roughly doubled their earlier assessment of that play (mostly this was due to not including the Three Forks in their earlier assessment.)
see slide 17 at the USGS Bakken/Three Forks Assessment presentation.
   In light of this I decided to increase the earlier (1.73 Gb) Eagle Ford estimate of undiscovered technically recoverable resources(TRR) from the USGS by a factor of 2.3 to 4 Gb.  To determine total TRR, the proved reserves and oil already produced need to be added to the undiscovered TRR, in the case of the Eagle Ford output to the end of 2011 was only 0.1 Gb and proved reserves were about 1 Gb (check the EIA data on the change in proved reserves since 2009 in districts 1 and district 2 of Texas):

So for the Eagle Ford estimated TRR would be 4+1=5 Gb.

For the North Dakota Bakken undiscovered TRR is 5.8 Gb, 2.2 Gb of proven reserves, and 0.5 Gb of oil produced for a Total TRR of 8.5 Gb. See my previous post for more details.

For the rest of the US we can deduct Bakken (7.38 Gb), Eagle Ford(1.73 Gb), and Alaska(0.94 Gb) from the US total (13 Gb) which leaves about 3 Gb, now assume that a reassessment by the USGS increases this by a factor of 2.3 to 7.2 Gb, then add the Montana Bakken/Three Forks (1.6 Gb) and reserves from the Permian basin and other plays (1.3 Gb) to get 9.2 Gb for a TRR estimate for US “other LTO”(Total LTO minus [North Dakota Bakken/Three Forks plus Eagle Ford play]). Total TRR for all US LTO is 22.7 Gb. (I have assumed LTO from Alaska’s North Slope will not be produced.)

For the North Dakota Bakken/Three Forks and Eagle Ford plays we use the following economic assumptions to find the Economically Recoverable Resource (ERR):

OPEX (operating expenditure) is $4/barrel, royalty and tax payments are 24.5 % of wellhead revenue, annual discount rate is 12 % (used to find the net present value[NPV] of a well over its 30 year life). Transport costs are $12/barrel for the Bakken and $3/barrel for the Eagle Ford.  Well costs are 9 million for the Bakken in Jan 2013 and fall by 8% per year to 7 million in 2016 and for the Eagle Ford well costs are $8 million in Jan 2013 and fall 8% per year to $6.5 million in mid 2017.  Real oil prices follow the EIA’s 2013 Annual Energy Outlook reference case to 2040 and then continue to rise at the 2030 to 2040 rate to the end of the scenario.  All costs and prices are in May 2013$ so they are real prices rather than nominal prices.
The concept of ERR is discussed in detail in the Sept, 2013 post after figure 3.

Figure 1

fig 2
I will use the Eagle Ford play as my template because it has ramped up much more quickly than the Bakken, this is a very optimistic scenario and it is unlikely that there will be greater output from US LTO than the scenario I will present.

The underlying assumptions are:
-the average well will look like the average Eagle Ford well
-ramp up of additional wells will be slow until the peak of combined Bakken and Eagle Ford output
-in 2015 the Bakken and Eagle Ford peak and reach break even levels of profitability by 2016
-in response to reaching break even the number of new wells per month added in both the ND (North Dakota) Bakken and the Eagle Ford are reduced substantially.
-new wells added in the other US LTO plays ramp up as the rate that wells added to the Bakken and EF are reduced
As before we adjust the decrease in new well EUR (both when it begins and how long it takes to reach its maximum) so that the TRR matches our estimate of 9.2 Gb.  In this case the EUR starts to decrease in July 2018 and reaches its maximum monthly rate of decrease of 2.37 % in June 2020. The “other LTO” peaks in 2020 at about 2 MMb/d.
To determine ERR we make identical economic assumptions as our Eagle Ford case above except that we assume transport costs are $5/barrel on average ($3/barrel in EF case).

Figure 2

fig 3

When we combine our North Dakota Bakken/Three Forks, Eagle Ford, and “other LTO” models we get the following chart:

Figure 3

fig 4

This scenario is indeed optimistic, but not nearly as optimistic as the EIA’s scenario for LTO in the 2013 Annual Energy Outlook.  For comparison I computed the ERR for 2013 to 2040 for my US LTO scenario, it was 17.6 Gb over that period, the EIA scenario has a total output of 24.5 Gb over the same period, 40% higher output than an already optimistic scenario.  My guess is that reality will lie between the blue curve and the green curve with the most likely peak around 2018+/- 2 years at about 3.1+/- 0.2 MMb/d.

Dennis Coyne

 Appendix Bakken and Eagle Ford Details
I am still working on this section, check back for details
Using the USGS TRR estimates as our guide we assume new well estimated ultimate recovery (EUR) eventually decreases as the room for new wells in the most productive areas (the sweet spots) starts to run out.  If new wells are producing an average of 450 kb over 30 years before this decrease begins, we assume at some point, say June 2014 the new well EUR starts to decrease maybe by 0.4% per month, the rate of decrease continues to increase for 18 months so that after 18 months the new well EUR is decreasing at a monthy rate of 7.2 %.

fig 5

fig 6

‘Watch what we do, not what we say’: Shell cancels U.S. gas-to-liquids plant

‘Watch what we do, not what we say’: Shell cancels U.S. gas-to-liquids plant.

When civil rights advocates grew restless because of President Richard Nixon’s right-wing rhetoric on the issue of desegregation, then-Attorney General John Mitchell told them, ”Watch what we do, not what we say.”

Those following the hype over America’s supposed newfound abundance of oil and natural gas would do well to follow that advice when evaluating what oil and gas company executives and their surrogates say.

When Royal Dutch Shell pulled the plug on its U.S. gas-to-liquids project recently, the company offered the same explanation it used when it shut down its oil shale project earlier this year: Shell sees better opportunities elsewhere. This explanation–much like the I’m-resigning-to-spend-more-time-with-my-family explanation–tends to deflect questions about why things aren’t working out.

What’s not working out for Shell is a planned $20 billion plant in Louisiana designed to turn natural gas into diesel, jet fuel, lubricants and chemical feedstocks, products typically produced by oil refineries. The plug was pulled, however, while the project was still in the planning stage.

Shell did actually say a little more about why it is abandoning the project in this almost inscrutable piece of corporate prose:

 Despite the ample supplies of natural gas in the area, the company has taken the decision that GTL is not a viable option for Shell in North America, at this time, due to the likely development cost of such a project, uncertainties on long-term oil and gas prices and differentials, and Shell’s strict capital discipline.

Now, here’s the same paragraph translated into simple English:

 The plant is going to cost a lot more to build than we thought it would. Natural gas prices are going up and could easily make it uneconomical to produce diesel and jet fuel from natural gas when compared to making them from oil. And, we don’t have unlimited funds to spend on everything we think of just to see if it works.

Shell CEO Peter Voser has voiced doubts about the so-called “shale revolution” in the United States (which refers to advances in drilling technology that have opened previously inaccessible shale deposits of natural gas and oil to exploitation). In fact, Shell took a $2.1 billion write-down on its shale assets in the United States. In lay terms, the company had to reduce the value of those assets on its balance sheet to reflect reality. The company also sold small tight oil fields related to shale deposits, fields that it no longer wishes to develop.

Voser said he still believes Shell’s remaining $24 billion investment in U.S. shale gas and tight oil will “be a success story for Shell.” Three-quarters of that investment is devoted to natural gas from shale. But, Voser added that the potential for natural gas and oil from shale elsewhere in the world has been “a little bit overhyped” citing concerns specifically about Europe.

Now, because this rhetoric is coming from an oil industry CEO, we can assume that he is walking the line between saying things which will get him removed from the invitation lists of his fellow oil executives’ cocktail parties–things otherwise known as the awful truth–and misrepresenting the facts to shareholders, which would get him into trouble in other ways.

But abandoning the gas-to-liquids plant speaks much more loudly than Voser’s actual remarks. It means Voser expects that natural gas prices simply won’t stay low long enough to make such a huge investment pay off. And, that means that he doesn’t believe the hype about an ongoing glut of U.S. natural gas.

So, Voser directs Shell to abandon a gas-to-liquids plant, the profitability of which would be destroyed by high prices for the natural gas which the plant must purchase. At the same time, he has Shell retain most of its shale gas wells, a move which only makes sense if he expects U.S. natural gas prices to go higher. And, those prices will only go higher if there is increased demand or reduced supply, or a combination of both.

It’s not hard to figure out the meaning of what Peter Voser is doing. But it is understandably difficult to shut out the constant din of abundance stories sponsored by the industry and its well-financed public relations machine–that is, until you understand that it’s not what the industry says that’s important, but what it actually does.

 

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