Oil shales come in two flavours, those with immature kerogen and those with mature kerogen. In the immature case, the kerogen has not yet been converted to liquid oil, so the kerogen must be matured in situ or in a surface facility by the use of heat. A muture oil shale has liquid hydrocarbons and are often termed "tight oil" plays.


For immature oil shales, rock samples are analyzed in the laboratory using a process called Fuscher analysis, giving an oil yield in US gallons per ton of rock. Mature oil shales are analyzed using conventional core analysis coupled with standard geochemical and total organic carbon analysis.


The immature oil shale case is shown on the rest of this web page. See tight oil plays for the mature kerogen special case.,


The distinguishing characteristic of an immature "oil shale" is that it contains significant organic carbon but no free oil or gas. This hydrocarbon is immature, not yet transformed into oil by natural processes, and are usually termed "source rocks". Some adsorbed and some free gas may also exist. Immature oil shales require a specialized log analysis model because the Archie saturation model is often inappropriate.


Immature oil shale can be mined on the surface or at depth and the rock heated in a retort to convert the organic content to oil. Some valuable by products such as vanadium may also be extracted, but dry clay, ash, and other minerals are a serious waste disposal issue. In-situ extraction using super-heated steam, air, carbon dioxide, or some other heat transfer system is used to convert the organic carbon to oil. Collector wells then extract the oil.

Immature oil shales have been exploited since the mid 1800's. An interesting radio show gives a brief history and an over-hyped future for the Colorado -Utah-Wyoming immature oil shales as seen from the post-war perspective of 1946. Click HERE to listen. You can fast-forward over the first 5 minutes to avoid some really bad scene-setting dialogue. And they "forgot" to mention that Canada was the first to commercially produce kerosene from shale oil in 1846.



Immature oil shale has received many different names over the years, such as cannel coal, boghead coal, alum shale, stellarite, albertite, kerosene shale, bituminite, gas coal, algal coal, wollongite, schistes bitumineux, torbanite, and kukersite. Some of these names are still used for certain types of oil shale. Recently, however, attempts have been made to systematically classify the many different types of oil shale on the basis of the depositional environment of the deposit, the petrographic character of the organic matter, and the precursor organisms from which the organic matter was derived.

A useful classification of oil shales was developed by A.C. Hutton. He divided oil shale into three groups based on their deposition environment: terrestrial, lacustrine, and marine, and further by the origin of their organic matter.


Terrestrial oil shales include those composed of lipid-rich organic matter such as resin spores, waxy cuticles, and corky tissue of roots and stems of vascular terrestrial plants commonly found in coal-forming swamps and bogs. Lacustrine oil shales include organic matter derived from algae that lived in fresh, brackish, or saline lakes. Marine oil shales are composed of organic matter derived from marine algae unicellular organisms, and marine dinoflagellates.

Resistivity image log in lacustrine oil shale. White is high resistivity, black is low resistivity.

Within these three groups, Hutton recognized six specific oil-shale types, as shown in the diagram above:


    1. Cannel coal is brown to black oil shale composed of resins, spores, waxes, and cutinaceous and corky materials derived from terrestrial vascular plants together with varied amounts of vitrinite and inertinite. Cannel coals originate in oxygen-deficient ponds or shallow lakes in peat-forming swamps and bogs.

    2. Lamosite is pale, grayish-brown and dark gray to black oil shale in which the chief organic constituent is lamalginite derived from lacustrine planktonic algae. Other minor components include vitrinite, inertinite, telalginite, and bitumen. The Green River oil-shale deposits in western United States and a number of the Tertiary lacustrine deposits in eastern Queensland, Australia, are lamosites.

    3. Marinite is a gray to dark gray to black oil shale of marine origin in which the chief organic components are lamalginite and bituminite derived chiefly from marine phytoplankton. Marinite may also contain small amounts of bitumen, telalginite, and vitrinite. Marinites are deposited typically in epeiric seas such as on broad shallow marine shelves or inland seas where wave action is restricted and currents are minimal. The Devonian–Mississippian oil shales of eastern United States are typical marinites. Such deposits are generally widespread covering hundreds to thousands of square kilometers, but they are relatively thin, often less than 100 m.


    4. Torbanite, named after Torbane Hill in Scotland, is a black oil shale whose organic matter is composed mainly of telalginite found in fresh- to brackish-water lakes. The deposits are commonly small, but can be extremely high grade.


    5. Tasmanite, named from oil-shale deposits in Tasmania, is a brown to black oil shale. The organic matter consists of telalginite derived chiefly from unicellular algae of marine origin and lesser amounts of vitrinite, lamalginite, and inertinite.


    6. Kukersite, which takes its name from Kukruse Manor near the town of Kohtla-Järve, Estonia, is a light brown marine oil shale. Its principal organic component is telalginite derived from green algae. Kukersdite is the main type of oil shale in Estonia and westtern Russiaa, and is burned instead of coal  to generate electricity in power plants.



Canada produced some shale oil from deposits in New Brunswick in the mid-1800's. The mineral was called Albertite and was originally believed to be a form of coal.


Albert Mines, New Brunswick, in 1850's


Later, the nature of the mineral and its relation to the surrounding oil shale was described correctly. Abraham Gesner used Albertite in his early experiments to distill liquid fuel from coal and solid bitumen. He is credited with the invention of kerosene in 1846, and built a significant commercial distillery to provide lighting oil to replace whale oil in eastern Canada and USA. In the 1880's, shale oil was abandoned as a source of kerosene in favour of distillation from liquid petroleum.


Canada's oil-shale deposits range from Ordovician to Cretaceous age and include deposits of lacustrine and marine origin in at least 20 locations across the country. During the 1980s, a number of the deposits were explored by core drilling. The oil shales of the New Brunswick Albert Formation, lamosites of Mississippian age, have the greatest potential for development. The Albert oil shale averages 100 l/t of shale oil and has potential for recovery of oil and may also be used for co-combustion with coal for electric power generation.

Marinites, including the Devonian Kettle Point Formation and the Ordovician Collingwood Shale of southern Ontario, yield relatively small amounts of shale oil (about 40 l/t), but the yield can be doubled by hydroretorting. The Cretaceous Boyne and Favel marinites form large resources of low-grade oil shale in the Prairie Provinces of Manitoba, Saskatchewan, and Alberta. Upper Cretaceous oil shales on the Anderson Plain and the Mackenzie Delta in the Northwest Territories have been little explored, but may be of future economic interest.

Determining OIL YIELD (Grade) of Oil Shale FROM ROCK SAMPLES
The grade of oil shale has been determined by many different methods with the results expressed in a variety of units. The heating value of the oil shale may be determined using a calorimeter. Values obtained by this method are reported in English or metric units, such as British thermal units (Btu) per pound of oil shale, calories per gram (cal/gm) of rock, kilocalories per kilogram (kcal/kg) of rock, megajoules per kilogram (MJ/kg) of rock, and other units.

The heating value is useful for determining the quality of an oil shale that is burned directly in a power plant to produce electricity. Although the heating value of a given oil shale is a useful and fundamental property of the rock, it does not provide information on the amounts of shale oil or combustible gas that would be yielded by retorting (destructive distillation).

The grade of oil shale can be determined by measuring the yield of oil of a shale sample in a laboratory retort. The method commonly used in Canada and United States is called the modified Fischer assay, first developed in Germany, then adapted by the U.S. Bureau of Mines. The technique was subsequently standardized as the ASTM Method D-3904-80. Some laboratories have further modified the Fischer assay method to better evaluate different types of oil shale and different methods of oil-shale processing.

The standardized Fischer assay consists of heating a 100-gram sample crushed to –8 mesh (2.38-mm mesh) screen in a small aluminum retort to 500ºC at a rate of 12ºC per minute and held at that temperature for 40 minutes. The distilled vapors of oil, gas, and water are passed through a condenser cooled with ice water into a graduated centrifuge tube. The oil and water are then separated by centrifuging. The quantities reported are the weight percent of shale oil, water, shale residue, and “gas plus loss” by difference. Some organic matter is turned to char and reported as part of the shale residue. As a result, this assay may understate the amount of oil that might be recovered in a commercial scale retort that continuously mixes the feedstock. Oil yield is usually converted from mass fraction into US or Imperial gallons per ton (gpt or gal/t) of rock. So much for going metric! In Canada, oil yields are quoted in liters per metric ton of rock (l/t).

Oil shale example from Utah; density log (left), sonic (middle, Fischer oil yield in gallons/ton (right). Note sonic scale is reverse of conventional oilfield practice. Low density and high sonic travel time correspond to high oil yield, analogous to high porosity in conventional oilfield applications.


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