Conventional oil production will peak and decline until reserves are exhausted within the next several decades. In an effort to secure fuel resources for the future once conventional sources have been depleted, we are continuing to look into the wide reserves of oil shale. This article will give a brief overview of oil shale and extraction technologies with examples of pilot plants in the United States, and comment on the viability of the technology.
Oil shale refers to a sedimentary rock formation rich in non-soluble organic matter called kerogen, which can be processed into gaseous and liquid hydrocarbons. Like petroleum deposits, kerogen is derived from the decomposition of various plants but has not been exposed to significant pressure and heat for a period of time for conversion into liquid hydrocarbons. This conversion can be achieved using pyrolysis, the heating of hydrocarbons in an anoxic environment to produce gaseous and liquid hydrocarbons known as "shale oil" and coke, a solid carbonaceous material.
Global reserves of oil shale are large enough to produce an estimated 3.2 trillion barrels of shale oil.  In comparison, the total world reserves of conventional oil, as of 2009, are 1.3 trillion barrels.  In the United States alone (Mainly in the Green River Basin encompassing Colorado, Utah, and Wyoming), some estimates claim there are over 2.8 trillion barrels and 1.5 trillion in the Piceance Basin in Colorado, alone. [3,4] One and a half trillion barrels of oil is enough to supply the United States for 220 years at its current rate of consumption. 
However, unlike conventional oil, oil shale is very difficult to extract and process. As a solid, oil shale does not flow at native temperatures, and the useful kerogen must also be separated from the clay deposits. Additionally, the content and composition of kerogen can vary significantly between deposits. The carbon, oxygen, and hydrogen percent compositions determine the fraction of usable liquid and gaseous hydrocarbons that can be produced, and the Fischer Assay quantifies the overall amount of oil that can be produced per amount of oil shale. Furthermore, pyrolysis requires significant energy input, which diminishes the overall energy returns.
Extraction methods can be categorized into ex-situ methods, in which shale oil is mined from the earth's crust and subsequently retorted (pyrolized) to produce oil, and in-situ methods, where kerogen is heated in place and then piped to the surface through wells. All of the commercial operations currently in use utilize ex-situ processing, and the major operations are in Estonia, China, and Brazil. Ex-situ methods require mining of the raw oil shale - either on the surface or underground. While surface mining can lead to higher production rates of shale oil, they also incur more irreversible ecological damage than underground mining, which does not permit high-volume processing. Additionally, there are many other environmental concerns such as the disposal of waste, exorbitant water use, air pollution, and greenhouse gas emission.
The proposed in-situ methods of extraction attempt to mitigate the environmental impact while maintaining a high energy output. Six of the ten pilot oil shale projects in the United States involve in-situ mining for these attractive environmental reasons. Other advantages of the in-situ process include the ability to extract more total shale oil even in lower-grade deposits and from deeper deposits. However, in-situ techniques requires the drilling of many wells and a significant energy input required to convert kerogen into extractable liquid. Two examples of pilot technologies include Royal Dutch Shell's In-situ Conversion Process (ICP) and American Shale Oil's Conduction Convection and Reflux (CCR) process.
Shell has been working on the ICP since 1981, and they have expanded their test operations to seven sites in Colorado.  The ICP involves digging an array of heating wells 7.8 meters apart in which electrical heaters will raise the oil shale temperature to 340-400°C, converting the kerogen to shale oil over about four years.  Other wells are dug to remove groundwater before heating, to extract the vapor and liquid hydrocarbons, and to monitor the groundwater. At Shell's test site in Colorado, the oil shale they are attempting to extract is found at depths between 270 and 590 meters below the ground. This layer also contains groundwater, and to reduce the risk of groundwater contamination from released hydrocarbons and other pollutants created through the ICP process, they are also creating a "freeze wall," which is comprised of a series of wells dug around the perimeter of the extraction site and filled with a coolant kept at -40°C.  This creates an impenetrable frozen barrier through which additional groundwater will not enter the extraction zone and hydrocarbons will not leave.
Shell reports high liquid recovery efficiencies of above 60% Fischer Assay and claims an Energy Return on Energy Invested of 3 to 4 for their Mahogany Research Pilot Plant, although independent life cycle assessments say their net energy output ratio (including internally and externally-generated energy) could be as low as 1.2-2.5 depending on how they manage their resources and the quality of the deposits, and additionally claims that the overall process will have a larger greenhouse gas emission than conventional oil. 
The American Shale Oil (AMSO) CCR process is targeted at obtaining shale oil from deeper deposits with less surface activity. AMSO's pilot plant neighbors Shell's in Colorado's Piceance Basin, but instead of extracting oil shale in the 270-590 meter range that overlaps with groundwater, they claim that at approximately 600-700 meters, there is an illitic shale deposit isolated from groundwater by a nahcolitic cap rock.  Heat will be applied by digging a heating well vertically down to below the illitic shale deposit and then horizontally underneath it. When this well is heated below the illitic shale deposit at 340°C, it will convert kerogen into oil, which will boil, rise, cool, and condense in a convection and reflux pattern, which they believe will induce faster heat transfer than the ICP process. Secondary wells (either horizontal or vertical) will then be used to collect the freed hydrocarbons.
AMSO's CCR technology would have less of a surface impact than Shell's ICP, as horizontal wells could be dug from a single line of surface sites rather than an extensive grid; however this does limit AMSO to developing oil shale only from 600-700 meters, whereas the ICP enables collection of shale oil from various depths, at the cost of a freeze wall and a greater number of wells. Nevertheless, AMSO projects that in an 8 square mile area, they could produce about 100,000 bbl/day of shale oil for 25 years. 
Oil shale currently provides only a minor supply of energy to most of the world with the exception of Estonia, and can only emerge as a player in the world market if conventional oil prices remain permanently high. Due to the relatively high-cost (both energetically and economically) extraction of shale oil compared to conventional petroleum, it cannot directly compete with petroleum, even though the world holds enormous reserves. However, as conventional oil reserves dwindle and the demand for liquid fuel is met by short supply, and as oil shale pilot plants demonstrate their viability, oil shale technology might expand enough to become a major oil supply.
© 2010 Steven M. Herron. The author grants permission to copy, distribute and display this work in unaltered form, with attribution to the author, for noncommercial purposes only. All other rights, including commercial rights, are reserved to the author.
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