To access the full paper, download the PDF on the left-hand sidebar.

Introduction

Are We Running Out of Oil?

For decades, experts have been debating the timing of a peak in the discovery and production of conventional oil reserves. In 1998, geologist Colin Campbell predicted that global production of conventional oil would begin to decline within 10 years. His forecast, commonly referred to as “peak oil,” was endorsed and elaborated on by many respected geologists and commentators, including Princeton University geologist Kenneth Deffeyes. At the heart of most predictions of peak oil is a prediction made by Marion King Hubbert in 1956. In the mid-1950s, Hubbert used a curve-fitting technique to correctly predict that U.S. oil production would peak by 1970. The so-called Hubbert curve is now widely used in the analysis of peaking production of conventional petroleum. According to the Hubbert curve, the production of a finite resource, when viewed over time, will resemble an inverted U, or a bell curve. This follows from the technical limits of exploitation, where the estimated parameters of the curve determine the rate of ascent and descent before and after the peak. “Peak oil” is the term used to describe the situation where the rate of oil production reaches its absolute maximum and begins to decline.

Hubbert’s thesis has been applied to world oil production, and peak oil advocates have in recent years been arguing that the majority of the world’s oil production was concentrated in mature, aging fields from which the extraction of additional supplies will be increasingly costly as mechanical or chemical aids are used to induce artificial (as opposed to natural) lift. According to Peak Oil Theory, as each older field peaks, world production will fall and oil prices will rise.

Part and parcel of this depletion-oriented view of world oil resources is the conventional wisdom that as mature fields become rapidly depleted in the Western world, the last remaining barrels will be found in the most prolific oil basins of the Middle East. To meet an ever-increasing demand for oil, so the argument goes, oil prices will have to rise significantly to accommodate the exploitation of more expensive, technically complex unconventional resources, such as oil and natural gas from shale deposits, oil sands, and other difficult geologic formations. This geologically based world oil market structure is thus predicted to bring Middle East producers increasingly higher returns for their remaining scarce supplies in the coming years, as competition from conventional resources in other regions such as North America, Latin America, Africa, and Asia fades with depletion.

This view of the world oil market gained renewed popularity in the 2000s as oil prices were climbing. Rising prices were explained as evidence of increasing depletion across the globe, including the Middle East, and commentators speculated that a looming crisis was on the horizon. However, we will argue that technology has increasingly upended traditional discussions of impending oil scarcity and created a world where the costs of developing unconventional oil, the costs of converting one form of hydrocarbon to another, and the costs of providing alternative automotive engine technologies have rendered almost all energy sources increasingly substitutable for one another. The increasing substitutability of other fuels for oil will temper oil demand and prices.

We suggest further that artificial and geopolitical barriers to resource exploitation in the Middle East, by creating a temporary scarcity premium, have hastened technological innovation in unconventional resources at a time when resource abundance still remains a strong feature of the world energy market. Moreover, the higher oil prices rise and the longer they remain high, the faster the pace of technology development and substitution will be, irrespective of the stage of depletion world oil markets are experiencing.

Thus, rather than reap ever-higher returns for their remaining conventional resources, Middle East producers may find themselves facing increasing competition for market share with unconventional supplies of oil from Canadian oil sands, North American shale oil, shale gas, and liquids converted from natural gas supplied at prices that are driven by technological innovation rather than depletion curves. At the same time, temporary price spikes have encouraged oil-consuming countries to adopt energy efficiency measures that will curb the long-term growth in global oil demand, potentially delaying the timeframe when actual depletion may benefit the Middle East, if it comes at all.

The Current Facts of World Oil Production

Dire predictions that world oil production rates would begin to fall by the 2000s did not, in fact, materialize. Our ability to produce more oil from countries outside of the Organization of Petroleum Exporting Countries (OPEC) has not actually declined in recent years, though the rate of gain has slowed. In 2010, non-OPEC production rose by roughly 850,000 barrels a day (b/d) to 47.771 million b/d, up from 46.913 million b/d in 2009, despite significant declines in the United Kingdom (7.7 percent), and Norway (9.4 percent). U.S. oil production actually gained for the second consecutive year from 7.271 million b/d in 2009 to 7.513 million b/d in 2010, and this trend would have likely gained momentum but for the Macondo accident and related drilling moratorium. Energy Intelligence Group is projecting non-OPEC production to grow by 450,000 b/d or so in 2011 based on gains from South America and the former Soviet Union while the International Energy Agency (IEA) is forecasting a 300,000 b/d increase for 2011. Investment firm Morgan Stanley is more pessimistic, projecting that large gains from the former Soviet Union, South America, and Canada will be offset by sharp declines elsewhere, leaving a net loss in non-OPEC production of 380,000 b/d in 2011.

As oil and natural gas prices were rising sharply in the 2000s, investments aimed at developing unconventional resources similarly skyrocketed, opening up new domains for oil and natural gas production not previously expected in mainstream forecasts for the 2000s and 2010s. Onshore United States is the best case in point where shale oil production is now on the rise, with output from the Bakken play in North Dakota growing from less than 100,000 b/d in 2005 to an estimated 375,000 b/d for 2011.5 Innovations in the Bakken shale—such as longer lateral lengths and the use of multistage fractures—have allowed production rates to increase dramatically in recent years. In fact, these innovations have led some analysts to predict that despite the projected declines in offshore output due to the extended moratorium, total U.S. oil production will remain relatively flat largely because of oil supply increases from the Bakken shale, which is projected to increase to up to 800,000 b/d by 2013.

The cost of production for Bakken liquids is in line with the costs of conventional U.S. onshore production. Moreover, current high prices are stimulating interest in Wyoming oil shale as well. Based on small-scale field tests, Shell has argued that shale oil “will be competitive at crude oil prices in the mid-$20s per barrel.” If true, this would certainly be a game-changer in the oil world, in much the same way recent developments in shale gas have been for natural gas markets.

Oil shale resources such as those in the Green River Basin in the Western U.S. are distinct from the shale oil deposits of the Bakken play. The distinction is largely related to the differences in geologic and physical properties, which result in the use of different recovery techniques for extraction. On the one hand, shale oil is developed by creating porosity in a liquids-rich shale formation. There is no reservoir to be tapped into that allows the flow of hydrocarbons to the wellbore due to pressure differential. Rather, the “reservoir” and resultant flow are created through the act of fracturing the shale formation. Oil shale, on the other hand, is a solid so cannot be pumped directly from the ground. Instead, it is developed either through conventional mining techniques and processed to a liquid above ground or through in-situ retorting, a process by which the rock is heated and the oil pumped to the surface in liquid form.

The resource assessments for oil shale are far larger than those for shale oil, but recovery is also generally more costly. In a 2005 study, the Rand Corporation wrote:

The largest known oil shale deposits in the world are in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming. Estimates of the oil resource in place within the Green River Formation range from 1.5 to 1.8 trillion barrels. Not all resources in place are recoverable. For potentially recoverable oil shale resources, we roughly derive an upper bound of 1.1 trillion barrels of oil and a lower bound of about 500 billion barrels. For policy planning purposes, it is enough to know that any amount in this range is very high. For example, the midpoint in our estimate range, 800 billion barrels, is more than triple the proven oil reserves of Saudi Arabia. Present U.S. demand for petroleum products is about 20 million barrels per day. If oil shale could be used to meet a quarter of that demand, 800 billion barrels of recoverable resources would last for more than 400 years.

The Rand report goes on to say that surface mining is “unlikely to be profitable unless real crude oil prices are at least $70 to $95 per barrel (2005 dollars).” The report does not minimize the difficulties of developing the resource. In fact, it concludes, “Under high growth assumptions, an oil shale production level of 1 million barrels per day is probably more than 20 years in the future, and 3 million barrels per day is probably more than 30 years into the future.” But Shell’s experience, noted above, indicates that costs could come down quickly over time with more investment.

This material may be quoted or reproduced without prior permission, provided appropriate credit is given to the author and Rice University’s Baker Institute for Public Policy. The views expressed herein are those of the individual author(s), and do not necessarily represent the views of Rice University’s Baker Institute for Public Policy.