[ This is a great introduction to the whole topic of oil, reserves, resources, and so on. It’s very long so I’ve only excerpted bits of it and reworded some of it.  I can’t say there’s anything new in here that’s not already in energyskeptic posts, but this article pulls it all together at one of the top scientific institutions in the world.  Yes, it’s from 2013, but I like publishing older articles long after to see how good their vision of the future was.

Alice Friedemann   www.energyskeptic.com  author of “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report ]

Miller, R.G., Sorrell, S. R. 2 December 2013. The future of oil supply. Philosophical transactions of the Royal Society, Mathematical, physical, and engineering sciences.

Figure 2. Classification of hydrocarbon liquids.

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.

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.  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%. Most of these giant fields are relatively old, many are well past their peak of production, 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. Future global production is therefore heavily dependent on the future prospects of the giant fields.

PEAK OIL: 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 (my comment: but most of our oil is conventional and significantly cheaper and energy efficient than NGLs, oil sands, and tight oil).  On a per capita basis, 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.

It’s the size of the tap, not the tank that matters

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. 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.

The production of conventional oil must eventually decline to almost zero, because it is a finite resource.

Decline rates

From a sample of 77 post-peak UK fields, we estimate an average decline rate of approximately 12.5% per year, so the average rate of decline from post-peak fields is a critical determinant of  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. This is lower than the average decline rate, since larger fields tend to decline more slowly.

Offshore fields decline faster than onshore fields and that newer fields decline faster than older fields. 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. 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.

The production cycle for tight oil resources is driven by a 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, regional tight oil production can only be maintained through the continuous drilling of closely spaced wells. But tight oil plays are heterogeneous, with much higher well productivity in the ‘sweet spots’ than elsewhere. So when the sweet spots become exhausted, it becomes increasingly difficult to maintain regional production. Based upon these considerations, Hughes 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.

Based upon these considerations, the IEA anticipates crude oil production from existing fields falling from 68.5 mb per day in 2011 to only 26 mb per day in 2035, but hopes for 65.4 due to undiscovered oil fields and additional production from unconventional oil, with no peak before 2035.

This IEA estimate has received much criticism from scientists.  For example, Höök et al. argue that production from existing fields could decline more quickly than the IEA assumes, while Aleklett et al.argue that the projections rely upon implausible assumptions about the rate at which fallow and undiscovered fields can be developed and produced. 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.

Far more important than predicting the exact date of global peak is how will we cope after it happens.  But although 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 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) and ignored the environmental consequences of expanding the supply of non-conventional resources. Avoiding these would necessarily restrict the range of available options.

NGLS can’t fill in for crude oil: 33% less energy and only 33% can be made into transportation fuel

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 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. 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.

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.

Murphy 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.