Shale oil extraction

Shale oil extraction


Main article: History of the oil shale industry

A.C. Kirk’s retort, used in the mid-to-late 19th century, was one of the first vertical oil shale retorts.

A number of shale oil extraction technologies have evolved over a period of time. In the 10th century, a method of extracting oil from „some kind of bituminous shale“ was described by the Arabian physician Masawaih al-Mardini (Mesue the Younger). The first shale oil extraction patent was granted by the British Crown in 1694 to three people who had „found a way to extract and make great quantities of pitch, tarr, and oyle out of a sort of stone“. Modern industrial extraction of shale oil originated in France with the implementation of a process invented by Alexander Selligue in 1838 and about a decade later in Scotland by implementation of the process invented by James Young. During the late 19th century, shale oil extraction plants were built in Australia, Brazil, Canada, and the United States. The 1894 invention of the Pumpherston retort (also known as the Bryson retort) marked the separation of oil shale industry from the coal industry.

China (Manchuria), Estonia, New Zealand, South Africa, Spain, Sweden, and Switzerland began extracting shale oil in the early 20th century. However, crude oil discoveries in Texas during the 1920s and in the Middle East during mid-century brought most oil shale industries to a halt. In 1944, the United States restarted shale oil extraction as part of its Synthetic Liquid Fuels Program. These industries continued until oil prices fell sharply in the 1980s. The last oil shale retort in the United States, operated by Unocal Corporation, closed in 1991. The United States‘ oil-shale development program was restarted in 2003, followed by a commercial leasing program in 2005 permitting the extraction of oil shale and oil sands on federal lands in accordance with the Energy Policy Act of 2005.

As of 2009[update], shale oil extraction is in operation in Estonia, Brazil, and China. While, Australia, U.S. and Canada have tested shale oil extraction techniques with demonstration projects and are planning implementation on a commercial basis, Morocco and Jordan are also planning to start shale oil production. Only four technologies are in commercial use; namely Kiviter, Galoter, Fushun, and Petrosix.

Process principle

Overview of shale oil extraction

Shale oil extraction process decomposes oil shale and converts kerogen in oil shale into shale oil petroleum-like synthetic crude oil. The process is conducted by pyrolysis, hydrogenation, or thermal dissolution. The most common extraction method is pyrolysis (also known as retorting). In this process, oil shale is heated until its kerogen decomposes into vapors of a condensable shale oil and non-condensable combustible oil shale gas. Oil vapors and oil shale gas are collected and cooled, causing the shale oil to condense. In addition, oil shale processing produces spent shale, which is a solid residue. Spent shale may contain char (some authors use the terms coke residue or semi-coke instead of char) carbonaceous residue formed from kerogen. Depending on the exact composition of oil shale, other useful by-products are also generated during this process. These include ammonia, sulfur, aromatic compounds, pitch, asphalt, and waxes. The efficiency of extraction processes is often evaluated by comparing their yield to the results of a Fischer Assay performed on a sample of the shale.

Pyrolysis is an endothermic process that requires an external source of energy. Most technologies use other fossil fuels such as natural gas, oil, or coal to generate heat, but various experimental methods have used electricity, radio frequency, microwaves, or reactive fluids for this purpose. By-products of the retorting process such as oil shale gas and char may be burned as an additional source of energy and the heat contained in spent oil shale and oil shale ash may be reused to pre-heat the raw oil shale.

The temperature at which perceptible decomposition of oil shale occurs depends on the time-scale of the process. In ex situ retorting processes, it begins at 300 C (570 F) and proceeds more rapidly and completely at higher temperatures. The rate of decomposition is the highest when the temperature ranges between 480 C (900 F) and 520 C (970 F). The ratio of oil shale gas to shale oil generally increases along with retorting temperatures. For a modern in situ process, which might take several months of heating, decomposition may be conducted at temperatures as low as 250 C (480 F). Temperatures below 600 C (1,110 F) are preferable, preventing the decomposition of lime stone and dolomite in the rock and thereby limiting carbon dioxide emissions and energy consumption.

Hydrogenation and thermal dissolution (reactive fluid processes) extract the oil using hydrogen donors, solvents, or a combination of these. Thermal dissolution involves the application of solvents at elevated temperatures and pressures, increasing oil output by cracking the dissolved organic matter. Different methods produce shale oil with different properties.


Industry analysts have created several classifications of the methods by which hydrocarbons are extracted from oil shale.

By process principles: Based on the treatment of raw oil shale by heat and solvents the methods are classified as pyrolysis, hydrogenation, or thermal dissolution.

By location: A frequently used distinction considers whether processing is done above or below ground, and classifies the technologies broadly as ex situ (displaced) or in situ (in place). In ex situ processing, also known as aboveround retorting, the oil shale is mined either underground or at the surface and then transported to a processing facility. In contrast, in situ processing converts the kerogen while it is still in the form of an oil shale deposit, following which it is then extracted via oil wells, where it rises in the same way as conventional crude oil.

By heating method: The heating methods used to decompose oil shale may be classified as direct or indirect. While methods that burn materials or insert heat carriers within the retort are classified as direct, methods that conduct heat through retort walls are described as indirect. As of 2009, most of the commercial retorts in operation or under development are direct heating retorts. Another classification is based upon whether the heat is delivered by solids (hot recycled solids methods) or gases. In principle, it is less expensive to deliver heat using solids, especially those already heated by the shale’s pyrolysis, as is the case when spent shale particles are used.

By retort style: Based on the materials and methods used to heat the oil shale to an appropriate temperature, its processing technologies have been classified into internal combustion, hot recycled solids, wall conduction, externallyenerated hot gas, reactive fluid, and volumetric heating methods. There are many possible realizations and combinations of these methods, which are summarized in the table shown below. Some processing technologies are difficult to classify due to their unique methods of heat input (e.g. ExxonMobil Electrofrac) or due to limited information.

Classification of processing technologies by heating method and location (according to Alan Burnham)

Heating Method

Above ground (ex situ)

Underground (in situ)

Internal combustion

Gas combustion, NTU, Kiviter, Fushun, Union A, Paraho Direct, Superior Direct

Occidental Petroleum MIS, LLNL RISE, Geokinetics Horizontal, Rio Blanco

Hot recycled solids

(inert or burned shale)

Alberta Taciuk, Galoter, Lurgi-Ruhrgas, TOSCO II, Chevron STB, LLNL HRS, Shell Spher, KENTORT II

Conduction through a wall

(various fuels)

Pumpherston, Hom Tov, Fischer Assay, Oil-Tech, EcoShale In-Capsule Process, Combustion Resources

Shell ICP (primary method), American Shale Oil CCR, IEP Geothermic Fuel Cell Process

Externally generated hot gas

PetroSIX, Union B, Paraho Indirect, Superior Indirect, Syntec process (Smith process)

Chevron CRUSH, Petro Probe, MWE IGE

Reactive fluids

IGT Hytort (high-pressure H2), donor solvent processes, Chattanooga fluidized bed reactor

Shell ICP (some embodiments)

Volumetric heating

IIT Research Institute, Lawrence Livermore National Laboratory, and Raytheon radiofrequency processes, Global Resource microwave process, Electro-Petroleum EEOP

By raw oil shale particles‘ size: The various ex situ processing technologies may be differentiated by the size of the oil shale particles that are fed into the retorts. As a rule, oil shale „lumps“ varying in diameter from 10 millimeters (0.4 in) to 100 millimeters (3.9 in) are used in internal hot gas carrier technologies, while oil shale that has been crushed into particulates less than 10 millimeters (0.4 in) in diameter are used in internal hot solid carrier technologies.

By complexity of technology: In situ technologies are usually classified either as true in situ processes or modified in situ processes. True in situ processes do not involve mining or crushing the oil shale. Modified in situ processes involve drilling and fracturing the target oil shale deposit to create voids for the improved flow of gases and fluids through the deposit, thereby increasing the volume and quality of the shale oil produced.

Ex situ technologies

Internal combustion

Internal combustion technologies burn materials (typically char and oil shale gas) within a vertical shaft retort to supply heat for pyrolysis. Typically raw oil shale is fed into the top of the retort and is heated by the rising hot gases, which pass through the descending oil shale, thereby causing decomposition. Shale oil vapors and evolving gases are then moved to a condensing system. Condensed shale oil is collected, while non-condensable gas is recycled and used to carry heat. In the lower part of the retort, spent oil shale is heated to about 900 C (1,650 F) to burn off the char. Recycled gas enters the bottom of the retort and cools the spent oil shale. The Union and Superior multimineral processes depart from this pattern. In the Union process, oil shale is fed through the bottom of the retort and a pump moves it upward. In the Superior multimineral process, oil shale is processed in a horizontal segmented doughnut-shaped traveling-grate retort.

These processes are thermally efficient, since much of the carbon within the shale is burnt, and can achieve 80-90% of Fischer assay yield. Two well-established shale oil industries use internal combustion technologies: Kiviter process facilities have been operated continuously in Estonia since the 1920s, and China’s Fushun Mining Group, a world leader in shale oil production, operates Fushun process facilities. Their product streams, however, are diluted by combustion exhaust.

Hot recycled solids

Hot recycled solids technologies deliver heat to the shale via solid particlesypically oil shale ash. These technologies usually employ rotating kiln retorts, fed by fine oil shale particles generally having a diameter of less than 10 millimeters (0.4 in); some technologies use particles even smaller than 2.5 millimeters (0.10 in). The particles are heated in a separate chamber or vessel, advantageously preventing the dilution of oil shale gas with combustion exhaust.

In the Galoter process, the spent oil shale is burnt in a separate furnace and the resulting hot ash is mixed with oil shale particles to cause decomposition. This process and its modified version, Enefit, have been used in Estonia’s Narva Oil Plant for several decades. The TOSCO II process uses hot shale ash and ceramic balls heated by contact with the ash. The distinguishing feature of the Alberta Taciuk process (ATP) is that the entire process occurs in a single rotating multihamber horizontal vessel. An ATP plant extracted 1.5 million barrels (238.4809410^3 m3) of shale oil between 2000 and 2005 at the Stuart Oil Shale Plant, but is now being dismantled.

Alberta Taciuk Processor retort

Conduction through a wall

These technologies transfer heat to the oil shale by conducting it through the retort wall. The shale feed usually consists of fine particles. Their advantage lies in the fact that retort vapors are not combined with combustion exhaust. The Combustion Resources process uses a hydrogenired rotating kiln, where hot gas is circulated through an outer annulus. The Oil-Tech staged electrically heated retort consists of individual inter-connected heating chambers, stacked atop each other. Its principal advantage lies in its modular design, which enhances its portability and adaptability. The Red Leaf Resources EcoShale In-Capsule Process combines surface mining with a lower-temperature heating method similar to in situ processes by operating within an earthen impoundment structure. Inside the impoundment, a hot gas circulated by parallel pipes heats the oil shale rubble. As the impoundment could be constructed in the empty space created by mining, it allows rapid reclamation of the topography.

Externally generated hot gas

In general, externally generated hot gas technologies are similar to internal combustion technologies in that they also process oil shale lumps in vertical shaft kilns. Significantly, though, the heat in these technologies is delivered by gases heated outside the retort vessel, and therefore the retort vapors are not diluted with combustion exhaust. The Petrosix process, used at the world’s largest operational surface oil shale pyrolysis retort in So Mateus do Sul, Paran, Brazil, employs this technology.

Reactive fluids

Reactive fluid technologies are suitable for processing oil shales with a low hydrogen content. In these technologies, hydrogen gas (H2) or hydrogen donors (chemicals that donate hydrogen during chemical reactions) react with coke precursors (chemical structures in the oil shale that are prone to form char during retorting but have not yet done so). The reaction roughly doubles the yield of oil, depending on the characteristics of oil shale and process technology.

Reactive fluids technologies include the IGT Hytort (high-pressure H2) process, donor solvent processes, and the Chattanooga fluidized bed reactor. In the IGT Hytort oil shale is processed in a high-pressure hydrogen environment. The Chattanooga process uses a fluidized bed reactor and an associated hydrogen-fired heater for oil shale thermal cracking and hydrogenation.

In situ technologies

In situ technologies heat oil shale underground by injecting hot fluids into the rock formation, or by using linear or planar heating sources followed by thermal conduction and convection to distribute heat through the target area. Shale oil is then recovered through vertical wells drilled into the formation. These technologies are potentially able to extract more shale oil from a given area of land than conventional ex situ processing technologies, as the wells can reach greater depths than surface mines. They present an opportunity to recover shale oil from low-grade deposits that traditional mining techniques could not extract.

During World War II a modified in situ extraction process was implemented without significant success in Germany. One of the earliest successful in situ processes was the underground gasification by electrical energy (Ljungstrm method) process exploited between 1940 and 1966 for shale oil extraction at Kvarntorp in Sweden. Prior to the 1980s, many variations of the in situ process were explored in the United States. The first modified in situ oil shale experiment in the United States was conducted by Occidental Petroleum in 1972 at Logan Wash, Colorado. The newest technologies explore a variety of heat sources and heat delivery systems.

Wall conduction

Shell’s freeze wall for in situ shale oil production was designed to separate the process from its surroundings

Wall conduction in situ technologies use heating elements or heating pipes placed within the oil shale formation. The Shell in situ conversion process (Shell ICP) uses electrical heating elements for heating the oil shale layer to between 650 F (340 C) and 700 F (370 C) over a period of approximately four years. The processing area is isolated from surrounding groundwater by a freeze wall consisting of wells filled with a circulating super-chilled fluid. Disadvantages of this process are large electrical power consumption, extensive water use, and the risk of groundwater pollution. The process, under development since the early 1980s, was tested at the Piceance Basin Mahogany Research Project. 1,700 barrels (270 m3) of oil were extracted in 2004 at a 30-by-40-foot (9.1 by 12 m) testing area.

American Shale Oil CCR Process

In the American Shale Oil CCR Process, superheated steam or another heat transfer medium is circulated through a series of pipes placed below the oil shale layer to be extracted. The system combines horizontal wells, through which steam is passed, and vertical wells, which provide both vertical heat transfer through refluxing of converted shale oil and a means to collect the produced hydrocarbons. Heat is supplied by combustion of natural gas or propane in the initial phase and by oil shale gas at a later stage.

The Independent Energy Partners‘ Geothermic Fuels Cells Process (IEP GFC) extracts shale oil by exploiting a high-temperature stack of fuel cells. The cells, placed in the oil shale formation, are fueled by natural gas during a warm-up period and afterward by oil shale gas generated by its own waste heat.

Externally generated hot gas

Chevron CRUSH process

Externally generated hot gas in situ technologies use hot gases that are heated above-ground and then injected into the oil shale formation. The Chevron CRUSH process, developed in partnership with Los Alamos National Laboratory, injects heated carbon dioxide into the formation via drilled wells and heats the formation through a series of horizontal fractures in which the gas circulates. Petro Probe has proposed a process which involves injecting super-heated air into the oil shale formation. Mountain West Energy’s In Situ Vapor Extraction process uses similar principles of injection of high-temperature gas.

ExxonMobil Electrofrac

Main article: ExxonMobil Electrofrac

ExxonMobil’s in situ technology uses electrical heating with elements of both wall conduction and volumetric heating methods. It injects an electrically conductive material such as calcined petroleum coke into the hydraulic fractures created in the oil shale formation which then forms a heating element. Heating wells are placed in a parallel row with a second horizontal well intersecting them at their toe. This allows opposing electrical charges to be applied at either end.

Volumetric heating

Artist’s rendition of a radio wave-based extraction facility

The concept of oil shale volumetric heating by radio waves (radio frequency processing) was developed at the Illinois Institute of Technology during the late 1970s. This technology was further developed by Lawrence Livermore National Laboratory. The oil shale would be heated by vertical electrode arrays. Deeper volumes could be processed at slower heating rates by installations spaced at tens of meters. The concept presumes a radio frequency at which the skin depth is many tens of meters, thereby overcoming the thermal diffusion times needed for conductive heating. While the Laboratory has not conducted a rigorous evaluation of the concept, private investigations may have been undertaken. Its drawbacks include intensive electrical demand and the possibility that groundwater or char would absorb undue amounts of the energy.

Radio frequency processing in conjunction with critical fluids is being developed by Raytheon together with CF Technologies and tested by Schlumberger, while Global Resource Corporation is testing microwave heating. Electro-Petroleum proposes electrically enhanced oil recovery by the passage of direct current between cathodes in producing wells and anodes located either at the surface or at depth in other wells. The passage of the current through the oil shale formation results in resistive Joule heating. Microwave heating technologies are based on the same principles as radio wave heating, although it is believed that radio wave heating is an improvement over microwave heating because its energy can penetrate farther into the oil shale formation.


NYMEX light-sweet crude oil prices 19962009 (not adjusted for inflation)

Main article: Oil shale economics

The dominant question for shale oil production is under what conditions shale oil is economically viable. The various attempts to develop oil shale deposits have succeeded only when the shale-oil production cost in a given region is lower than the price of petroleum or its other substitutes. According to a survey conducted by the RAND Corporation, the cost of producing a barrel of shale oil at a hypothetical surface retorting complex in the United States (comprising a mine, retorting plant, upgrading plant, supporting utilities, and spent shale reclamation), would range between US$7095 ($440600/m3), adjusted to 2005 values). Assuming a gradual increase in output after the start of commercial production, the analysis projects a gradual reduction in processing costs to $3040 per barrel ($190250/m3) after achieving the milestone of 1 billion barrels (16010^6 m3). Royal Dutch Shell has announced that its Shell ICP technology would realize a profit when crude oil prices are higher than $30 per barrel ($190/m3), while some technologies at full-scale production assert profitability at oil prices even lower than $20 per barrel ($130/m3).

To increase the efficiency of oil shale retorting and by this the viability of the shale oil production, researchers have proposed and tested several co-pyrolysis processes, in which other materials such as biomass, peat, waste bitumen, or rubber and plastic wastes are retorted along with the oil shale. Some modified technologies propose combining a fluidized bed retort with a circulated fluidized bed furnace for burning the by-products of pyrolysis (char and oil shale gas) and thereby improving oil yield, increasing throughput, and decreasing retorting time.

A critical measure of the viability of oil shale as an energy source lies in the ratio of the energy produced by the shale to the energy used in its mining and processing, a ratio known as „Energy Returned on Energy Invested“ (EROEI). A 1984 study estimated the EROEI of the various known oil shale deposits as varying between 0.713.3; some companies and newer technologies assert an EROEI between 3 and 10. To increase the EROEI, several combined technologies were proposed. These include the usage of process waste heat, e.g. gasification or combustion of the residual carbon (char), and the usage of waste heat from other industrial processes, such as coal gasification and nuclear power generation. The water needed in some extraction processes offers an additional economic consideration: this may pose a problem in areas with water scarcity.

Environmental considerations

Main article: Environmental impact of the oil shale industry

Objections to its potential environmental impact have stalled governmental support for extraction of shale oil in some countries, e.g. Australia. Shale oil extraction may involve a number of different environmental impacts that vary with process technologies. Depending on the geological conditions and mining techniques, mining impacts may include acid drainage induced by the sudden rapid exposure and subsequent oxidation of formerly buried materials, the introduction of metals into surface water and groundwater, increased erosion, sulfur gas emissions, and air pollution caused by the production of particulates during processing, transport, and support activities. Surface mining for ex situ processing, as with in situ processing, requires extensive land use and ex situ thermal processing generates wastes that require disposal. Mining, processing, spent shale disposal, and waste treatment require land to be withdrawn from traditional uses and should therefore avoid areas of high population density. Depending on the processing technology, the waste material may contain pollutants including sulfates, heavy metals, and polycyclic aromatic hydrocarbons, some of which are toxic and carcinogenic. Experimental in situ conversion processes may reduce some of these impacts, but may instead cause other problems, such as groundwater pollution.

The production and usage of oil shale usually generates more greenhouse gas emissions, including carbon dioxide, than conventional fossil fuels. Depending on the technology and the oil shale composition, shale oil extraction may create also sulfur dioxide, hydrogen sulfide, carbonyl sulfide, and nitrogen oxides emissions. Developing carbon capture and storage technologies may reduce the processes‘ carbon footprint.

Concerns have been prominently raised over the oil shale industry’s use of water, particularly in arid regions where water consumption is a sensitive issue. In some cases, oil shale mining requires the lowering of groundwater levels below the level of the oil shale strata, which may affect the surrounding arable land and forest. Above-ground retorting typically consumes between one and five barrels of water per barrel of produced shale oil, depending on technology. Water is usually used for spent shale cooling and oil shale ash disposal. In situ processing, according to one estimate, uses about one-tenth as much water.

A 2007 programmatic environmental impact statement issued by the United States Bureau of Land Management stated that surface mining and retort operations produce 2 to 10 US gallons (7.6 to 38 l; 1.7 to 8.3 imp gal) of waste water per 1 short ton (0.91 t) of processed oil shale.

See also

Oil shale geology

Oil shale reserves


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External links

Oil Shale. A Scientific-Technical Journal (ISSN 0208-189X)

Oil Shale and Tar Sands Programmatic Environmental Impact Statement (EIS) Information Center. Concerning potential leases of Federal oil sands lands in Utah and oil shale lands in Utah, Wyoming, and Colorado.

„Shale Oil Now“ Campaign. Links and articles on America’s shale oil compiled by Jon Moseley

The United States National Oil Shale Association (NOSA)

Shale Oil Information Center. A Colorado non-profit corporation disseminating information focusing on the history of the extraction of oil shale and oil sands.

v  d  e

Petroleum industry


Petroleum engineering (Reservoir simulation  Seismic to simulation)  Petroleum geology  Geophysics  Seismic (Seismic inversion)  Petrophysics  Core sampling


Drilling engineering  Underbalanced drilling  Directional drilling  (Measurement while drilling  Geosteering)  Drilling fluid  Drill Stem Test


Completion (Squeeze job)  Well logging  Pipeline transport  Tracers


Artificial lift (Pumpjack  ESP  Gas lift)  EOR (Steam injection  Gas reinjection)  Water injection  Well intervention  Upstream  Midstream  Downstream  Refining

Technical challenges

Differential sticking  Drilling fluid invasion  Blowouts  Lost circulation

Oil and gas agreements

Production sharing agreements  Concessions  Service Agreements  Risk agreements

Data by country

Total energy (consumption per capita  intensity)  Natural gas (consumption  production  reserves  imports  exports)  Petroleum (consumption  production  reserves  imports  exports)


ExxonMobil  Royal Dutch Shell  BP  Chevron Corporation  ConocoPhillips  Total S.A. (See also: National oil companies)

Major oil provinces

North Sea  East Texas  Persian Gulf  Athabasca oil sands  Gulf of Mexico  Venezuela  Niger Delta  Russia

Related articles

OPEC  History of petroleum  Peak oil  Oil price increases since 2003  Price of petroleum  Society of Petroleum Engineers

Categories: Oil shale technology | Petroleum production | Chemical engineeringHidden categories: Articles containing potentially dated statements from 2009 | All articles containing potentially dated statements

Source by ryyy