Unconventional oil

Oil sands generally consist of extra heavy crude oil or crude bitumen trapped in unconsolidated sandstone. These hydrocarbons are forms of crude oil that are extremely dense and viscous, with a consistency ranging from that of molasses for some extra-heavy oil to as solid as peanut butter for some bitumen at room temperature, making extraction difficult. These heavy crude oils have a density (specific gravity) approaching or even exceeding that of water. As a result of their high viscosity, they cannot be produced by conventional methods, transported without heating or dilution with lighter hydrocarbons, or refined by older oil refineries without major modifications. Such heavy crude oils often contain high concentrations of sulfur and heavy metals, particularly nickel and vanadium, which interfere with refining processes, although lighter crude oils can also suffer from sulfur and heavy metal contamination. These properties present significant environmental challenges to the growth of heavy oil production and use. Canada's Athabasca oil sands and Venezuela's Orinoco heavy oil belt are the best known example of this kind of unconventional reserve. In 2003 the estimated reserves were 1.2 trillion barrels (1.9×10¹¹ m³).[9]

Heavy oil sands and bituminous sands occur worldwide. The two most important deposits are the Athabasca Oil Sands in Alberta, Canada and the Orinoco heavy oil belt in Venezuela. The hydrocarbon content of these deposits is either crude bitumen or extra-heavy crude oil, the former of which is often upgraded to synthetic crude (syncrude) and the latter of which the Venezuelan fuel Orimulsion is based. The Venezuelan extra heavy oil deposits differ from the Canadian bituminous sands in that they flow more readily at Venezuela's higher reservoir temperatures and could be produced by conventional techniques, but the recovery rates would be less than the unconventional Canadian techniques (about 8% versus up to 90% for surface mining and 60% for steam assisted gravity drainage).[10]

In 2011, Alberta's total proven oil reserves were 170.2 billion barrels representing 11 percent of the total global oil reserves (1,523 billion barrels) and 99% of Canada's oil reserves. By 2011 Alberta was supplying 15% of the United States crude oil imports, exporting about 1.3 million barrels per day (210,000 m³/d) of crude oil.[10] The 2006 projections for 2015, were about 3 million barrels per day (480,000 m³/d). At that rate, the Athabasca oil sands reserves would last less than 160 years.[11] About 80 percent of Alberta's bituminous deposits can be extracted using in-situ methods such as steam assisted gravity drainage and 20 percent by surface mining methods.[10] The Northern Alberta oil sands in Athabasca, Cold Lake and Peace River areas contain an estimated 2 trillion barrels (initial volume in place) of crude bitumen and extra-heavy oil of which 9 percent was considered recoverable using technology available in 2013.[10]

It is estimated by oil companies that the Athabasca and Orinoco sites (both of similar size) have as much as two-thirds of total global oil deposits. They have only recently been considered proven reserves of oil. This is because oil prices have risen since 2003 and costs to extract oil from these mines have fallen. Between 2003 and 2008, world oil prices rose to over $140, and costs to extract the oil fell to less than $15 per barrel at the Suncor and Syncrude mines.

In 2013, crude oil from the Canadian oil sands was expensive oil to produce, although new US tight oil production was similarly expensive. Supply costs for Athabasca oil sands projects were approximately US$50 to US$90 per barrel. However, costs for Bakken, Eagle Ford and Niobrara were higher at approximately US$70 to US$90, according to 135 global oil and gas companies surveyed reported by the Financial Post.[12]

Extracting a significant percentage of world oil production from these deposits will be difficult since the extraction process takes a great deal of capital, human power and land. Another constraint is energy for project heat and electricity generation, currently coming from natural gas, which in recent years has seen a surge in production and a corresponding drop in price in North America. With the new supply of shale gas in North America, the need for alternatives to natural gas has been greatly diminished.

A 2009 study by CERA estimated that production from Canada's oil sands emits "about 5–15% more carbon dioxide, over the "well-to-wheels" lifetime analysis of the fuel, than average crude oil."[13] Author and investigative journalist David Strahan that same year stated that IEA figures show that carbon dioxide emissions from the tar sands are 20% higher than average emissions from oil.[14]

Tight oil, including light tight oil (sometimes confusingly the term 'shale oil' is used instead of 'light tight oil') is crude oil contained in petroleum-bearing formations of low permeability, often shale or tight sandstone.[15] Economic production from tight oil formations requires the same hydraulic fracturing and often uses the same horizontal well technology used in the production of shale gas. It should not be confused with oil shale, which is shale rich in kerogen, or shale oil, which is synthetic oil produced from oil shales.[16][17] Therefore, the International Energy Agency recommends to use the term "light tight oil" for oil produced from shales or other very low permeability formations, while World Energy Resources 2013 report by the World Energy Council uses the term "tight oil".[17][18]

Oil shale is an organic-rich fine-grained sedimentary rock containing significant amounts of kerogen (a solid mixture of organic chemical compounds) from which technology can extract liquid hydrocarbons (shale oil) and combustible oil shale gas. The kerogen in oil shale can be converted to shale oil through the chemical processes of pyrolysis, hydrogenation, or thermal dissolution.[19][20] The temperature when perceptible decomposition of oil shale occurs depends on the time-scale of the pyrolysis; in the above ground retorting process the perceptible decomposition occurs at 300 °C (570 °F), but proceeds more rapidly and completely at higher temperatures. The rate of decomposition is the highest at a temperature of 480 °C (900 °F) to 520 °C (970 °F). The ratio of shale gas to shale oil depends on the retorting temperature and as a rule increases with the rise of temperature.[19] For the modern in-situ process, which might take several months of heating, decomposition may be conducted as low as 250 °C (480 °F). Depending on the exact properties of oil shale and the exact processing technology, the retorting process may be water and energy extensives. Oil shale has also been burnt directly as a low-grade fuel.[21][22]

A 2016 estimate by the World Energy Council set total world shale oil resources at 6.05 trillion barrels. The United States is believed to hold more than 80% of that total[23]. There are around 600 known oil shale deposits around the world, including major deposits in the United States of America.[24] Although oil shale deposits occur in many countries, only 33 countries possess known deposits of possible economic value.[25][26] The largest deposits in the world occur in the United States in the Green River Formation, which covers portions of Colorado, Utah, and Wyoming. Approximately 70% of this resource lies on land owned or managed by the United States federal government.[27] Well-explored deposits, potentially possessing additional economic value, include the Green River deposits in the western United States, the Tertiary deposits in Queensland, Australia, deposits in Sweden and Estonia, the El-Lajjun deposit in Jordan, and deposits in France, Germany, Brazil, Morocco, China, southern Mongolia and Russia. These deposits have given rise to expectations of yielding at least 40 litres (0.25 bbl) of shale oil per tonne of shale, using the Fischer Assay method.[22][28]

According to a survey conducted by the RAND Corporation, the cost of producing a barrel of oil at a surface retorting complex in the United States (comprising a mine, retorting plant, upgrading plant, supporting utilities, and spent shale reclamation), would range between US$70–95 ($440–600/m³, adjusted to 2005 values).[29] As of 2008, industry uses oil shale for shale oil production in Brazil, China and Estonia. Several additional countries started assessing their reserves or had built experimental production plants.[21] In the US, if oil shale could be used to meet a quarter of the current 20 million barrels per day (3,200,000 m³/d) demand, 800 billion barrels (1.3×10¹¹ m³) of recoverable resources would last for more than 400 years.[29]

Thermal depolymerization (TDP) has the potential to recover energy from existing sources of waste such as petroleum coke as well as pre-existing waste deposits. This process, which imitates those that occur in nature, uses heat and pressure to break down organic and inorganic compounds through a method known as hydrous pyrolysis. Because energy output varies greatly based on feedstock, it is difficult to estimate potential energy production. According to Changing World Technologies, Inc., this process even has the ability to break down several types of materials, many of which are poisonous to both humans and the environment.[30]

Using synthetic fuel processes, the conversion of coal and natural gas has the potential to yield great quantities of unconventional oil and/or refined products, albeit at much lower net energy output than the historic average for conventional oil extraction.

In its day - prior to the drilling of oilwells to tap reservoirs of crude oil- the pyrolysis of mined solid organic-rich deposits was the conventional method of producing mineral oils. Historically, petroleum was already being produced on an industrial scale in the United Kingdom and the United States by dry distillation of cannel coal or oil shale in the first half of the 19th Century. Yields of oil from simple pyrolysis, however, are limited by the composition of the material being pyrolysed, and modern 'oil-from-coal' processes aim for a much higher yield of organic liquids, brought about by chemical reaction with the solid feedstuff.

The four primary conversion technologies used for the production of unconventional oil and refined products from coal and gas are the indirect conversion processes of the Fischer-Tropsch process and the Mobil Process (also known as Methanol to Gasoline), and the direct conversion processes of the Bergius process and the Karrick process.

Sasol has run a 150,000 barrels per day (24,000 m³/d) coal-to-liquids plant based on Fischer Tropsch conversion in South Africa since the 1970s.

Because of the high cost of transporting natural gas, many known but remote fields were not being developed. On-site conversion to liquid fuels are making this energy available under present market conditions. Fischer Tropsch fuels plants converting natural gas to fuel, a process broadly known as gas-to-liquids are operating in Malaysia, South Africa, and Qatar. Large direct conversion coal to liquids plants are currently under construction, or undergoing start-up in China.

Total global synthetic fuel production capacity exceeds 240,000 barrels per day (38,000 m³/d), and is expected to grow rapidly in coming years, with multiple new plants currently under construction.