Oil shale extraction

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Shell's experimental in situ oil shale facility, Piceance Basin, Colorado.
Shell's experimental in situ oil shale facility, Piceance Basin, Colorado.
Main articles: Oil shale and Oil shale industry

Oil shale extraction refers to the process in which kerogen, a mixture of organic chemical compounds found in oil shales, is converted into synthetic crude oil through the chemical process of pyrolysis. In this process, oil shale is heated in the absence of oxygen to a temperature at which oil shale is decomposed and kerogen is pyrolysed into a petroleum-like condensable shale oil—a form of non-conventional oil—and combustible shale gas (shale gas can also refer to gas occurring naturally in shales). The process also produces a solid residue in form of spent shale (char). Decomposition of oil shale begins at relatively low temperatures (300 °C (570 °F)), but proceeds more rapidly and more completely at higher temperature.[1]

The extraction techniques can be broadly classified into two primary methods, the ex situ method and the in situ method. There are hundreds of patents for oil shale retorting technologies.[2] However, only a few dozen have been tested in a pilot plant (with capacity 1 to 10 tonnes of oil shale per hour) and less than ten technologies have been tested at a demonstration scale (40 to 400 tonnes per hour). As of 2008, only four technologies are in commercial use, namely Kiviter, Galoter, Fushun, and Petrosix.[3]

The processes all require a source of heat. The non-condensible retort gas and char may be burnt and the heat energy may be reused for heating the raw oil shale or generating electricity. Also heat of the spent shale may be reused for the same purpose. Most commercial technologies burn the oil shale at the deposit to supply heat or reuse the spent shale, supplemented by gas or other fuels, although some experimental methods use electricity, radiofrequency and microwaves, reactive fluids. The heating methods may be direct or indirect heating and there are several methods for the heat transfer.[1][4] Almost all commercial retorts currently in operation or in development stages are internal heating retorts.[3]

Oil shale has gained attention as an energy resource as the price of conventional sources of petroleum has risen.[5] As of 2008, oil shale extraction is being undertaken in Estonia, Brazil and China, while some other countries such as Australia, USA, Canada and Jordan have planned to start or restore shale oil production.[6][7] The shale oil may be used as a fuel oil or upgraded to meet refinery feed specifications by adding hydrogen and removing impurities such as sulfur and nitrogen. At the same time, oil shale processing involve a number of environmental issues, such as waste disposal, extensive water use and waste water management, and air pollution.[8]

Contents

[edit] Classification of extraction technologies

Industry analysts have created several classifications of the methods by which hydrocarbons are extracted from oil shale. A frequently-used distinction considers whether retorting is done above or below ground, and classifies the technologies broadly as ex situ (off site) or in situ (on site). In the ex situ process, also known as above-ground retorting, the oil shale is mined and transported to a retort facility. By contrast, the in situ method converts the kerogen while it is still in the form of an oil shale deposit; it is then extracted via a well, where it rises in the same way as conventional petroleum.

However, based on the technique used to heat the oil shale to an appropriate temperature, its processing has also been classified into internal combustion, hot recycled solids, wall conduction, externally generated hot gas, reactive fluid, and volumetric heating methods. There are many possible realizations and combinations of these methods; therefore the following table is representative but not complete. Some processes are difficult to classify due to their unique methods of heat input (e.g. ExxonMobil's Electrofrac) or due to limited information.[4]

Classification of oil shale processing technologies according to heating method and location[4]
Heating Method Above Ground (ex situ) Below Ground (in situ)
Internal combustion Kiviter, Fushun, Union A, Paraho Direct, Superior Direct Oxy MIS, LLNL RISE, Geokinetics Horizontal, Rio Blanco
Hot recycled solids
(inert or burned shale)		 Alberta Taciuk, Galoter, Lurgi, TOSCO II, Chevron STB, LLNL HRS, Shell Spher -
Conduction through a wall
(various fuels)		 Pumpherston, Hom Tov, Fischer Assay, Oil-Tech, EcoShale In-Capsule Process, Combustion Resources Shell ICP (primary method), EGL Oil Shale Process, 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), Xtract Technology (supercritical solvent extraction), Donor solvent processes, Chattanooga fluid bed reactor Shell ICP (some embodiments)
Volumetric heating - ITTRI, LLNL and Raytheon radiofrequency processes, Global Resource microwave process, Electro-Petroleum EEOP

The heating methods used to decompose the rock may be classified as direct or indirect. Only internal combustion technologies are classified as direct - all other heating technologies are described as indirect. Based on whether gases or circulated solids are used to transfer heat, heating methods have been further divided into internal hot gas carrier technologies (e.g. internal combustion technologies and externally generated hot gas technologies) and internal hot solid carrier technologies (those using hot recycled solids to transfer heat to the oil shale and those using wall conduction).[1][3][4]

Some analysts use the size of the oil shale particles that are fed into the retorts to differentiate the various ex situ extraction processes. As a rule, oil shale "lumps" varying in diameter from 10 to 100 millimetres (0.4 to 4 in) are used in internal hot gas carrier technologies, while oil shale that has been crushed into particulates less than 10 millimetres/0.4 inches in diameter is used in internal hot solid carrier technologies.[3]

[edit] Ex situ technologies

In case of the ex situ method, the oil shale is mined either by underground or surface mining and then transported to a processing facility. At the facility, the oil shale is heated, usually to 450 °C to 500 °C (840 °F to 930 °F), at which temperature the kerogen in the oil shale decomposes to gas, oil vapor and char. This process is known as retorting. The gas and oil vapors are separated from the spent shale and cooled, causing the oil to condense.

[edit] Internal combustion technologies

Internal combustion technologies use for the heat transfer the flowing gases, which are generated by combustion within the retort. Common characteristics of these technologies are feeding by lump oil shale and the retort vapors are diluted with the exhaust generated by the combustion. The main technologies are Kiviter, Union A, Paraho Direct, Superior Direct, and Fushun processes.[4][9] The Kiviter processing takes place in the vertical shaft retort internally heated by combustion of coke residue (char) and non-condensable shale gas. Raw oil shale enters from the top of retort. It is heated by the rising gases, which pass sideward through the descending oil shale and carry the oil vapors and evolving gas into the collection chamber. From there the oil vapor is delivered to the condensing system. The shale residue is heated near 900 °C (1,650 °F) to burn off the char. Recycle gas entering the bottom of the retort cools the spent shale, which then leaves the retort through a water-sealed discharge system.[1] Main problems associated with Kiviter process are environmental concerns such as extensive use and pollution of water in the process, as also the waste solid residue which continues to leach toxic substances.[10][11] The Kiviter process is used by Estonian company VKG Oil, a subsidiary of Viru Keemia Grupp.[12] The company operates several retorts, the largest one, having a capacity of processing 40 tonnes per hour of oil shale.

Like the Kiviter retort, the Fushun-type retort is the vertical shaft kiln. The Fushun Mining Group in Liaoning Province, China operates the largest shale oil plant in the world. In 2003, it employed 80 Fushun-type retorts and as of 2007 it has increased to 180 retorts. Each retort processes about 4 tonnes per hour of shale.[13]

The Paraho Direct is an American version of the vertical shaft kiln.[14] This technology is used by Shale Technologies LLC in a pilot plant facility in Rifle, Colorado.[15]

[edit] Hot recycled solids technologies

Hot recycled solids technologies use solid particles (usually shale ash) to carry heat in the retorting zone. Typical characteristics of these technologies are the use of a rotating kiln, the feeding fine oil shale particles (less than 10 mm, in some technologies even less than 2.5 mm) and the heating of the heat carrier in a separate chamber or vessel, thus the retort vapors are not diluted with combustion exhaust. The main technologies in this category include Galoter, Alberta Taciuk Process (ATP), TOSCO II, Lurgi-Ruhrgas, Chevron STB, LLNL HRS, and Shell Spher processes.[4][9]

In the Galoter (also known as TSK or SHC) processing, dried oil shale is mixed with a hot (800 °C (1,470 °F)) solid shale ash, which is used as the heat carrier. The ash is obtained by combustion of the spent shale, burnt in a separate furnace.[11] The pyrolyse temperature in the Galoter retort is 520 °C (970 °F).[1] The Galoter process is more eco-friendly than the internal combustion technologies, as the use of water and pollution caused is minimal. However, the burning residue does cause some environmental problems due to organic carbon and calcium sulfide content.[10] The Galoter process is used for oil production by Eesti Energia, an Estonian energy company.[12] The company has two retorts, both processing 125 tonnes per hour of oil shale and plans are underway to build two more. It also plans to use this technology to construct a shale oil plant in Jordan.[16] VKG Oil is considering to construct a new production line using the Galoter process engineered by Atomenergoproject of Saint Petersburg.[17]

Alberta Taciuk Processor (ATP) retort
Alberta Taciuk Processor (ATP) retort

Similar to the Galoter process, the Alberta Taciuk processes oil shale fine particles in a rotating kiln. The unique feature of the Alberta Taciuk process is that drying and pyrolysis of the feed shale and the combustion, recycling and cooling of spent shale, all occur in a single multi-chamber horizontal, rotating vessel.[18][19] The water pollution caused by this process is quite limited.[10] Australian oil companies Southern Pacific Petroleum NL and later Queensland Energy Resources operated a 250 tonnes per hour industrial-scale pilot plant using the Alberta Taciuk Processor. The plant was shut down in 2004. UMATAC Industrial Processes is currently designing a 250 tonnes per hour Alberta Taciuk Processor in China.[20] Also VKG Oil has considered construction of a new retort facility using the Alberta Taciuk Processor.[12] Jordan Energy and Mining Ltd, a UK company, plans to use this technology at its oil shale project in Jordan.[21]

As with the Galoter and Alberta Taciuk process, the TOSCO II also processes oil shale fine particles which are heated with hot recycled solids in a rotating kiln. However, instead of recycling shale ash, the TOSCO II circulates hot ceramic balls between the retort and a heater. The process was tested in a 40 tonnes per hour test facility near Parachute, Colorado. The test facility was shut down in 1972. The LLNL HRS (hot-recycled-solid) retorting process was developed by the Lawrence Livermore National Laboratory. The technology was used in a 4 tonnes per day pilot plant from 1990 to 1993. A delayed-fall combustor, which is used in this process, gives greater control over the combustion process as compared to a lift pipe combustor, used in the Lurgi-Ruhrgas process, originally developed in the 1950s in Germany by Lurgi Corporation. Another difference between the LLNL HRS and the Lurgi-Ruhrgas processes is the usage of a fluidized-bed mixer in the LLNL HRS process, instead of the screw mixer, used in the Lurgi-Ruhrgas process.[4][12][22] The majority of the pyrolysis occurs in a settling-bed unit (plug flow).[4]

[edit] Conduction through a wall technologies

Conduction through a wall technologies transfer the heat by conduction through the retort wall. These technologies normally process fine particles and the retort vapors are not diluted by combustion exhaust. Technologies include Fischer Assay, Pumpherston, Hom Tov and Oil-Tech processes.[4][9] Fischer Assay is a standardized laboratory test that is used to measure the grade of an oil shale sample. A 100 gram sample crushed to <2.38 mm is heated in a small aluminum retort to 500 °C (930 °F) at a rate of 12 °C (54 °F) per minute, and held at that temperature for 40 minutes.[23] The distilled vapors of oil, gas, and water are passed through a condenser and cooled with ice water into a graduated centrifuge tube. The oil yields achieved by other technologies are often reported as a percentage of the Fischer Assay oil yield.

In the Hom Tov process, oil shale fine particles are slurried with waste bitumen and pumped through coils in a heater. Promoters of this process claim that the technology enables the shale to be processed at somewhat lower temperatures with the addition of the catalyzing bitumen. The technology has not been tested in a pilot plant yet.[24]

In the Red-Leaf Resources EcoShale In-Capsule Process, a hot gas generated by the burning of natural gas or pyrolysis gas. It is circulated through a pile of oil shale rubble using a set of parallel pipes. The heat is transferred to the shale through the pipe walls rather than being injected directly into the pile of oil shale rubble, thereby avoiding dilution of the pyrolysis gas with the heating gas. The pile of oil shale rubble is encapsulated by a low-cost earthen impoundment structure designed to prevent environmental contamination and to provide easy reclamation. Energy efficiency is enhanced by recovering heat from the spent shale by passing cool gas through the heating pipes and then using it to preheat adjacent capsules.[25][26]

A new process from Combustion Processes, Inc., seeks to eliminate carbon dioxide emissions from the shale oil production process. Pyrolysis occurs in a rotating kiln heated by hot gas flowing through an outer annulus. The hot gas is created by burning hydrogen generated in a separate unit by coal gasification followed by carbon dioxide separation. The annular geometry achieves heat transfer to the moving shale through a wall, thereby avoiding dilution of the product gas.[27]

Oil-Tech staged electrically heated retort process is developed by Millennium Synfuels, LLC (former Oil Tech Inc.). In this process, the crushed feed oil shale is lifted by a conveyor system to the vertical retort, loaded from the top. The retort is composed of a series of individual heating chambers, interconnected and stacked one upon the other. Heating rods extend into the centers of each of these chambers. The feed oil shale is heated to greater temperatures as it goes further down the retort, attaining a temperature of 1,000 °F (540 °C) in the lowest heating chamber. The gases and vapors are vacuumed into a condensing unit. The spent shale is used for pre-heating feed oil shale.[25][28] The advantages of this technology are the modular design allowing relative portability and adaptability, the process requires no water, high heating efficiency and relatively high product quality.[28]

[edit] Externally generated hot gas technologies

Externally generated hot gas technologies or indirectly heated technologies use heat, transferred by gases which are heated outside the retort vessel. The main technologies are Petrosix, Union B, Paraho Indirect, and Superior Indirect processes.[4][9] As with the internal combustion technologies, most of the externally-generated hot gas technologies process oil shale lumps in vertical shaft kilns; however, the retort vapors are not diluted with combustion exhaust. The world’s largest operational surface oil shale pyrolysis reactor is the Petrosix which is located in São Mateus do Sul, Paraná, Brazil. The 11 metres (36 ft) diameter vertical shaft kiln is owned by Petrobras and has been operating since 1992 with high availability. The company operates two retorts, the largest of which processes 260 tonnes per hour of oil shale.[12][29] Oil Shale Exploration Company LLC currently intends to use the Petrosix process as the technology to process the mined oil shale into shale oil at the White River Mine near Vernal, Utah.[30]

The largest retort ever built used the Union B technology, developed by Unocal. The Union B processed 400 tonnes per hour of oil shale lumps heated by externally generated hot gas. However, unlike all other vertical shaft kilns, the Union B pumped the oil shale into the bottom of the retort, with the hot gas entering at the top. Unocal operated the retort from 1986 to 1992 near Parachute, Colorado. The Paraho Indirect technology is similar to the Petrosix which is considered a highly reliable technology for use with U.S. oil shale.[12]

Two companies, Syntec Energy and Western Energy Partners, have proposed new hot gas processes based on linking coal gasification with rotating kiln retorts. The hot, hydrogen-rich synthesis gas from the coal gasifier is fed into the rotating kiln in direct contact with the oil shale, thereby heating it to pyrolysis temperature. The effluent synthesis gas is then used to generate electric power or other products typical of synthesis gas processes.[25]

[edit] Reactive fluids technologies

Reactive fluids technologies are IGT Hytort (high-pressure H2) process, Xtract Technology (supercritical solvent extraction), Donor solvent processes, and Chattanooga fluid bed reactor.[4][31][25] In the IGT Hytort process, developed by the Institute of Gas Technology (IGT), oil shales are processed at controlled heating rates in an atmosphere of hydrogen at high pressure.[32] This technology like other reactive fluid technologies, is more appropriate for oil shales with low hydrogen content, such as the Eastern US Devonian shales, for which only a third of the organic carbon is typically converted to oil during conventional overground retorting. The hydrogen or hydrogen donor (a chemical that donates hydrogen to others during chemical reactions) react with coke precursors (a chemical structure in the oil shale that is prone to form coke during retorting but has not yet done so) and roughly double the yield of oil, depending on the characteristics of the shale and process.[33]

Chattanooga Corp. has developed an extraction process which uses a fluid bed reactor and an associated hydrogen fired heater. In this process, retorting occurs at relatively low temperatures (1,000 °F/540 °C) through thermal cracking and hydrogenation into hydrocarbon vapors and spent solids. The thermal cracking allows for hydrocarbon vapors to be extracted off the oil shale which is then extracted and scrubbed of solids. The vapor is then cooled, during which condensate drops out of the gas and the remaining hydrogen, light hydrocarbon and acid gases are passed through an amine scrubbing system to remove hydrogen sulfide which is converted to elemental sulfur. The cleaned hydrogen and light hydrocarbon gases are then fed back into the system for compression or into the hydrogen heater which provides the heat for the fluid bed reactor. This nearly-closed-loop allows for a process where nearly all the energy needs are provided by the source material. The demonstration plant in Alberta was able to produce 930 barrels (~130 t) of oil per kilotonne of oil shale at an API gravity ranging between 28 to 30. With hydrotreating (the reaction of oil with high pressure hydrogen), it would be possible to improve this to 38-40 °API. Chattanooga Corp is currently looking at a design to produce a 2,500-barrel-per-hour (~330 t/h) facility.[25]

[edit] In situ technologies

In in situ processing technologies, the oil shale is heated underground. Potentially these technologies are able to extract more oil from a given area of land than conventional ex situ processing technologies, as the wells can reach greater depths than surface strip-mines.[34] Therefore in situ processing presents the opportunity of recovering shale oil from low-grade deposits, that may never be recovered by primary mining techniques.[35] Several companies have patented methods for in situ retorting. However, most of these methods are still in experimental stages.

The in situ technologies are usually classified as true in situ processes (TIS) and modified in situ processes (MIS). True in situ processes do not involve mining the oil shale. The modified in situ processes involve drilling and fracturing the target deposit above the mined area to create a void space of 20-25% which improves the flow of gases and liquid fluids through the rock formation, thereby increasing the volumes and quality of the oil produced.[12]

[edit] Early in situ processes

A variety of true in situ processes were tried prior to the oil shale crash in the 1980s. Most notable are the Equity Oil process, which injected superheated steam in the permeable leached zone of Colorado’s Piceance Basin,[36] and the Geokinetics Process, which is a horizontal combustion retort in which permeability is formed by explosive uplift and rubblization (the generation of rubble consisting of various sized fragments).[37][38] Little yield information is available from the Equity process, but the Geokinetics process generally recovered 40-50% of the Fischer Assay oil.[37]

Variations of the modified in situ (MIS) process have been investigated by the US Bureau of Mines, Lawrence Livermore National Laboratory, Occidental Petroleum, Rio Blanco Corporation, and Multi-Mineral Corporation. An early concept in the 1960s was to create a rubble chimney using a nuclear explosive.[39] However, this approach was abandoned for a variety of technical reasons. Subsequently, a variety of conventional mining and rubblization approaches were explored. The first MIS oil shale experiment was conducted by Occidental Petroleum in 1972 at Logan Wash.[12] Oil yield was adversely affected by inefficient sweep of the rubblized zone due to non-uniform permeability.[40] A subsequent series of field experiments aimed at improving permeability uniformity were carried out by using different mining and blasting techniques. Depending on different types of calculation used, Occidental achieved 50-60% Fischer Assay oil yield in Retorts 7 and 8.[40] Rio Blanco Corporation used a different mining and blasting approach which created a bed with close to 40% porosity. This enabled them to retort the chimney at a substantially faster rate and achieve higher oil yields around 70% of Fischer Assay.[41] Multi-Mineral Corporation proposed a more complicated MIS process for Saline Zone oil shale which included recovery of nahcolite and dawsonite minerals.[42]

[edit] Modern in situ processes

There has been a recent resurgence of interest in in situ recovery processes. In contrast to the 1980s emphasis on combustion retorting of subsurface rubble, current study focuses on true in situ processes, i.e. processes in which no shale removal or explosive uplift is used to create permeability. The processes can be separated by whether they inject hot fluids into the formation (Chevron CRUSH and Petro Probe) or use line or plane heating sources following by thermal conduction and convection to distribute heat through the formation (Shell ICP, EGL Resources, ExxonMobil Electrofrac). All but the Chevron CRUSH process are expected to produce a ~40 API gravity shale oil with fewer olefins and polar molecules due to in situ oil coking and cracking.

[edit] Conduction through a wall technologies

Shells Freeze Wall for in situ shale oil production
Shells Freeze Wall for in situ shale oil production

Conduction through a wall in situ technologies are the Shell's In situ Conversion Process (ICP), the EGL Resources Process and the IEP Geothermic Fuels Cells Process. Since 2000, the Shell Oil Company has been developing its in situ method under the Mahogany Research Project in Colorado, 200 miles (320 km) west of Denver, on Colorado's Western Slope. Though this method is energy intensive, it compares well to other heavy oil projects such as the tar sands. At full scale, it is estimated that for every unit of energy consumed, three to four units would be produced over the project life cycle.[43] A freeze wall is first constructed to isolate the region to be retorted from surrounding groundwater. 2,000 feet (610 m) wells, eight feet apart, are drilled and circulated with a super-chilled liquid to cool the ground to −60 °F (−50 °C). Water is then removed from the working zone. Heating and recovery wells are drilled on 40 feet (12 m) spacing within the working zone. Electrical heating elements are lowered into the heating wells and used to heat the kerogen to 650 °F (340 °C) to 700 °F (370 °C) over a period of approximately four years, slowly converting it into oil and gases, which are then pumped to the surface. Shell believes that it will be possible to recover around 65-70% of the hydrocarbons by this technique. An operation producing 100,000 barrels a day would require a dedicated power generating capacity of 1.2 gigawatts. To maximize the functionality of the freeze walls, working zones will be developed, adjacent to each other in succession. This in situ method requires 100% surface disturbance, greatly increasing the footprint of extraction operations in comparison to conventional oil and gas drilling. The current test sites are expected to produce in the region of 600 to 1,500 barrels per day (~84 to ~210 t/d).[43] Biggest challenges of the ICP technology are an extensive water use and a possible risk of groundwater pollution.[44]

EGL Oil Shale Process
EGL Oil Shale Process

The EGL Resources Process is a method which combines horizontal wells, through which steam is passed, and vertical wells, which provide both vertical heat transfer through refluxing of generated oil and a means to collect and produce the oil. In contrast to the Equity process, the steam circulates through a closed loop, and no fluids are injected into the formation. Horizontal heat transfer from the vertical wells is similar to that in the Shell ICP, and a similar quality of oil is expected. They are currently leasing a 160 acres (650,000 m²) tract in the Piceance Basin from the US Bureau of Land Management for their tests.[45][46]

In the Independent Energy Partners' Geothermic Fuels Cells Process (IEP GFC), a high-temperature fuel cell stack is placed in the formation to heat the ground. During an initial warm up period cells are fueled with an external source of natural gas), after which the process becomes self-fueling from gases liberated by its own waste heat. Raising the formation temperature increases fluid pressure in the heated zone to fracture oil shale. Alternatively, the formation can be pre-fractured to enhance the hydrocarbon flow between heating and producing wells. The IEP GFC is complained to have a net energy ratio of approximately 18 units of energy produced per unit used, when primary recovery is combined with residual char gasification and resulting syntheses gas.[25]

[edit] Externally generated hot gas technologies

Chevron CRUSH process
Chevron CRUSH process

Externally generated hot gas in situ technologies are the Chevron CRUSH process, the Petro Probe process, and the MWE IGE technology. Chevron Corporation and Los Alamos National Laboratory formed a joint research project in 2006 to develop the Chevron CRUSH process. They are investigating whether carbon dioxide can be injected into the formation at a raised temperature which will decompose the kerogen into conventional hydrocarbons. The carbon dioxide would be injected via conventionally drilled wells and then exposed to the formation via a series of horizontal fractures where it would circulate around. The hydrocarbons would then be produced via conventional vertical oil wells. This method is based upon research and trials carried out in the 1950s by Sinclair Oil which developed a method using natural and induced fractures between vertical wells to produce the in situ kerogen. Continental Oil (now ConocoPhillips) and the University of Akron also demonstrated and were issued patents which showed that carbon dioxide was a good carrier gas which helped recover the shale oil.[47]

Petro Probe, a subsidiary of Earth Science Search have listed a process which involves injecting super-heated air into wells drilled into the oil shale. The process involves injecting air which is super-heated at the surface, into wells drilled into the oil shale. The super-heated air then mixes and melts the in situ shale oil which is transported back to the surface in the form of gas which is then cooled and the condensate is collected. The remnant gas is then re-used to heat the air and is injected back with other waste products into the formation thereby minimizing the environmental impact.[25] The Mountain West Energy's In Situ Gas Extraction (MWE IGE; also known as In Situ Vapor Extraction) technology use same principles. High temperature gas injected into the oil shale layer to heat the oil shale to the decomposition. The gas sweeps the oil vapors to the surface where the oil is condensed and separated. The gas is then recirculated.[25][48]

[edit] ExxonMobil Electrofrac

ExxonMobil has been involved in oil shale development since the 1960s and is currently focusing on in situ developments. They are concentrating on an in situ method which heats the oil shale via an electrically conductive heating fluid injected into the reservoir which heats the oil shale via a series of hydraulic fractures. The oil shale is produced by separate dedicated production wells. It is thought that the most likely method is to have horizontal wells which have been hydraulically fractured along the vertical axis. These wells are placed in a parallel row with a second horizontal well intersecting them at their toe. This will allow the two different charges to be applied at either end. ExxonMobil is pursuing this method as they believe it provides a better method, which is to surround the oil shale and heat it up. The Electrofrac method has been tested in laboratories and test sites are now currently being considered for a field trial.[25]

[edit] Volumetric heating by radiowave, microwave, and direct current technologies

The concept of volumetric heating by radio waves (radio frequency processing) of oil shale was developed at Illinois Institute of Technology in the late 1970s. The concept was to heat modest volumes of shale, using vertical electrode arrays. Deeper large volumes could be processed at slower heating rates over a period of time. The technology was developed later by the Lawrence Livermore National Laboratory (LLNL), and by several other inventors. The LLNL concept was based on the use of wells spaced at tens of meters to heat vast expanse of deep oil shale very slowly. The concept presumed a radio frequency at which the skin depth is many tens of meters, and thereby overcoming the thermal diffusion times needed for conductive heating.[4][8] The microwave heating technology uses same principle as radio wave heating, although it is believed that radio wave heating technology is an advancement over microwave heating technology because the energy can penetrate farther into the formation.[49] The radio frequency processing technology is currently being tested by Raytheon Corporation, while Global Resource Corp. is still carrying on microwave heating tests.[49][50] Electro-Petroleum proposes electrically enhanced oil recovery (EEOR) by heating oil shale and generating shale oil by using direct current between cathodes in producing wells and anodes either at the surface or at depth in other wells. Passage of the current through the formation results in resistive Joule heating. This process has improved production from heavy oil fields in short term tests.[25][51]

[edit] Economics

Main article: Oil shale economics
Medium-term prices for light-sweet crude oil in US dollars, 2005–2007 (not adjusted for inflation)
Medium-term prices for light-sweet crude oil in US dollars, 2005–2007 (not adjusted for inflation)

During the early 20th century, the crude oil industry expanded. Since then, the various attempts to develop oil shale deposits have been successful only when the cost of shale oil production in a given region was less than the price of crude oil or its other substitutes.[52] 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 be between US$70–95 ($440–600/m3, adjusted to 2005 values). This estimate considers varying levels of kerogen quality and extraction efficiency. In order for the operation to be profitable, the price of crude oil would need to remain above these levels. The analysis also discusses the expectation that processing costs would drop after the complex was established. The hypothetical unit would see a cost reduction of 35–70% after its first 500 million barrels (79×106 m3) were produced. Assuming an increase in output of 25 thousand barrels per day (4.0×103 m3/d) during each year after the start of commercial production, the costs would then be expected to decline to $35–48 per barrel ($220–300/m3) within 12 years. After achieving the milestone of 1 billion barrels (160×106 m3), its costs would decline further to $30–40 per barrel ($190–250/m3).[53][54] A comparison of the proposed US oil shale industry to the Alberta tar sands industry has been drawn (the latter enterprise generated over one million barrels of oil per day in late 2007), stating that "the first-generation facility is the hardest, both technically and economically".[55][56]

Royal Dutch Shell has announced that its in situ extraction technology in Colorado could become competitive at prices over $30 per barrel ($190/m3), while other technologies at full-scale production assert profitability at oil prices even lower than $20 per barrel ($130/m3).[57][58][59][12] To increase the efficiency of oil shale retorting, several co-pyrolysis processes have been proposed and tested.[60][61][62][63][64]

Some commentators have compared shale-oil production unfavorably with other unconventional oil technologies, arguing that liquefaction of coal costs less money than oil-shale extraction, as well as producing more oil with fewer environmental impacts.[65] In 1972, the journal Pétrole Informations (ISSN 0755-561X) noted that one ton of coal yielded 650 litres (170 U.S. gal/140 imp gal) of oil while one ton of oil shale yielded only 150 litres (40 U.S. gal/33 imp gal) of shale oil.[29]

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 0.7–13.3.[66] Royal Dutch Shell has reported an EROEI of three to four on its in situ development, Mahogany Research Project.[57][43][67] An additional economic consideration is the water needed in the oil shale retorting process, which may pose a problem in areas with water scarcity.

[edit] Environmental considerations

Main article: Environmental impact of oil shale industry

Oil shale mining, necessary for ex situ retorting, involves a number of environmental impacts, more pronounced in surface mining than in underground mining. They 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.[8][68]

Oil shale extraction can damage the biological and recreational value of land and the ecosystem in the mining area. Combustion and thermal processing generate waste material. In addition, the atmospheric emissions from oil shale processing and combustion include carbon dioxide, a greenhouse gas. Environmentalists oppose production and usage of oil shale, as it creates even more greenhouse gases than conventional fossil fuels.[69] Section 526 of the Energy Independence And Security Act prohibits United States government agencies from buying oil produced by processes that produce more greenhouse gas emissions than would traditional petroleum.[70][71] Experimental in situ conversion processes and carbon capture and storage technologies may reduce some of these concerns in the future, but at the same time they may cause other problems, including groundwater pollution.[72]

Some commentators have expressed concerns over the oil-shale industry's use of water. Depending on technology, above-ground retorting uses between one and five barrels of water per barrel of produced shale oil.[53][73][74][75] A 2007 programmatic environmental impact statement issued by the US Bureau of Land Management stated that surface mining and retort operations produce two to ten US gallons (1.5–8 imperial gallons or 8–38 L) of wastewater per tonne of processed oil shale.[73] In situ processing, according to one estimate, uses about one-tenth as much water.[76] Water concerns are particularly sensitive issue in arid regions, such as the western US and Israel's Negev Desert, where there are plans to expand the oil shale industry despite a water shortage.[77][78]

Environmental activists, including Greenpeace, have organized strong protests against the industry. As a result, Queensland Energy Resources put the proposed Stuart Oil Shale Project in Australia on hold in 2004.[8][79][80]

[edit] See also

[edit] References

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