Unconventionally Speaking

Upgrading shale oil

Shale oil has many unique characteristics, some of which can create problems for conventional refineries.  Shale oil produced from in-situ conversion processes have better properties and when the process is designed and operated properly, has the potential to produce oil of such high quality that some of the upgrading and refining process can be eliminated.

Shale oil typically contains 1 to 2% nitrogen. This is a lot compared to conventional crude oils that are usually only .2% nitrogen. This high nitrogen content can poison conventional refinery catalysts.  The nitrogen can be a problem, but also represents an opportunity.  When shale oil is upgraded, an abundance of ammonia, NH3, is produced as a valuable by-product.  The reduced-nitrogen shale oil is then suitable as a petroleum feedstock for conventional refineries.  After nitrogen removal by hydrotreating and or other means, shale oils can contain less than 1 part per million of nitrogen (compared to 0.66 ppm for conventional crude oils).

There are many methods for nitrogen removal.  Many techniques involve simple washes of shale oil with solvents, usually acid solutions; other methods involve special catalysts, including halides of zinc, lead, copper, etc.  Economical catalysts for hydrodenitrogenation include nickel-molybdenum on alumina, cobalt molybdenum on alumina and nickel-tungsten on alumina. Nitrogen removal proceeds in the presence of these catalysts at temperatures and pressures which are also conducive to removal of sulfur and other hydrogenation reactions.  The result is denitrogenated shale oil with less than .3% nitrogen content. (U.S. Patent 4,272,362)

Hydrotreating is typically used to remove sulfur from crude oil, but can also remove nitrogen, and other contaminants like arsenic from shale oil.  In general terms, hydrotreating means the reaction of hydrocarbons with hydrogen, often in the presence of a catalyst.  Hydrotreating crude oil is an old technology that has been undergoing revitalization in the past decade due to more stringent requirements on sulfur content in diesel fuel and the availability of new technology.  British Petroleum contends that the rate of improvement in hydrotreating has matched the speed of technical advancement in computers for the last 10 years.  According to BP, over the past 20 years the sulfur content of diesel has been reduced by two orders of magnitude, while the cost of hydrotreating a barrel of diesel has fallen by 40%.

Catalysts are the key to hydrotreating. There are two main types commercially available, cobalt-molybdenum or nickel-molybdenum.  In a typical hydrotreatment process, crude oil is heated in the presence of hydrogen to temperatures in the range of 300°C – 380°C.  In the presence of the catalysts, hydrogen combines with sulfur to form H2S, and with nitrogen to produce ammonia. Metal contaminants like arsenic are deposited on the catalysts.

Hydrogen sulfide is a dangerous pollutant and requires further processing.  Typically, a solvent like diethanolamine (DEA) is bubbled through the crude after hydrotreating.  Hydrogen sulfide dissolves in the DEA which is then separated from the oil stream.  The DEA is then heated under low pressure, releasing the hydrogen sulfide in concentrated form.  The H2S gas is then treated in a two stage oxidation reaction involving catalysts to form water and pure molten sulfur.  The pure sulfur removed from the crude oil is, in itself, a valuable byproduct.  Ammonia recovered from nitrogen removal is also valuable, either as a byproduct, or as a feedstock for additional chemical processes.

Although shale oil has higher concentrations of nitrogen, it is typically lower in sulfur than many crude oils.  In the right facility, shale oil can be hydrotreated, through a hydrodenitrification process, to form a high quality refinery feed stock with a premium value.  Typical hydrogenation of shale oil requires hydrogen at 600-650 SCF/BBL to remove 1% nitrogen.  Therefore nitrogen removal could consume up to 1,300 SCF/BBL.  The in-situ recovery process used with Geothermic Fuel Cells involves substantial in-ground upgrading of the shale oil product.  As a result, substantially less hydrogen will be required for conventional upgrading in surface facilities.

In addition to the rapidly improving conventional hydrotreating technologies now available, new technical approaches are on the horizon.  For example, ultrasound has now been introduced as a means for low cost hydrotreating of crude oil.  Once nitrogen removal and hydrogenation have been completed, the shale oil will comprise a premium quality feedstock for refining into transportation fuels.  Typical product characteristics anticipated from Green River shale oil originating in the Piceance Creek Basin is as follows:

 

API Gravity 49
Specific Gravity .784
Sulfur 50 ppm
Nitrogen <1 ppm
Distillation   yields: Weight percent:
<200oC. 32%
200 -275 oC. 38%
275-325 oC. 20%
325-400 oC. 9%
400-538 oC. 1%

Strategic Significance of America’s Oil Shale Resource, Volume II Oil Shale Resources Technology and Economics, Office of Naval Petroleum and Oil Shale Reserves U.S. Department of Energy Washington, D.C., March 2004

For additional information check out these links:

http://www.ceri-mines.org/documents/28thsymposium/presentations08/PRES_3-2_Beer_Gary.pdf

http://www.ceri-mines.org/documents/28thsymposium/presentations08/PRES_3-3_Nair_Vijay.pdf

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