## Ceramatec licensing molten sodium technology for heavy oil upgrading; removing the need for diluent for bitumen

##### 10 April 2013
 Flowchart of Molten Sodium Upgrading process. Source: Field Upgrading. Click to enlarge.

An innovative oil-upgrading technology that can increase the economics of unconventional petroleum resources has been developed under a US Department of Energy-funded project. The technology, developed by Ceramatec and managed by the Office of Fossil Energy’s National Energy Technology Laboratory (NETL), has been licensed to Western Hydrogen of Calgary for upgrading bitumen or heavy oil from Canada. A new company, Field Upgrading (Calgary, Alberta), has been formed dedicated to developing and commercializing the Molten Sodium Upgrading (MSU) technology.

The MSU process involves mixing elemental molten sodium and small quantities of hydrogen or methane to reduce significantly the levels of sulphur, metals, TAN (total acid number) and asphaltenes in heavy oil feedstocks, including oil sands bitumen. MSU also significantly increases the API gravity of the feedstocks while achieving a relatively higher yield compared to conventional upgrading technologies. In the case of oil sands bitumen, the API gravity is increased from 8 API to more than 20 API, eliminating the need for diluent for pipeline transportation.

Molten Sodium Upgrading occurs in 3 general steps:

1. Removal of sulfur, nitrogen and metals from bitumen: Sodium, along with small quantities of hydrogen or methane, is mixed with bitumen to break down the bitumen molecule by preferentially seeking out and removing sulfur and nitrogen as salts and by precipitating metals.

2. Radical capping of upgraded molecules using hydrogen or methane: Hydrogen or methane attach to the open ends of molecules that were exposed after removing the sulfur and metals to prevent formation of cyclical hydrocarbons and olefins.

3. Regeneration of sodium using a patented ceramic transport membrane reactor developed by Ceramatec: The sodium salts are dissolved in a solvent, and introduced to the ceramic membrane reactor. When electricity is applied to the ceramic membrane, elemental sodium is extracted through the membrane and recycled to the process. The remaining product is elemental sulfur.

 Flowchart of molten salt gasification process. Source: Field Upgrading. Click to enlarge.

Benefits of the MSU process include:

• Simplification of the upgrading process and reduction of downstream upgrading/processing requirements: The reactivity of sodium allows for the removal of many conventional process units such as Claus Plants, cokers and hydrocrackers by combining sulfur removal, metals precipitation and upgrading in one simple step. MSU produces a sweet, pipeline ready heavy oil equivalent that requires minimal downstream processing prior to refining. Both of these benefits can potentially lead to doubling the net margin by greatly reducing the operating costs associated with upgrading and reducing the capital intensity by half.

• Major reduction in hydrogen consumption: MSU requires only a fraction of the hydrogen required in conventional upgrading, significantly reducing operating costs and the life cycle carbon dioxide emissions of hydrogen production and upgrading.

• Elimination of diluent use: The pipeline-ready MSU product can be put directly into the pipeline and shipped to market, eliminating the use of diluent for transportation and therefore greatly increasing the capacity of existing pipelines.

Addition of scalability and modularity to upgrading: The process equipment in MSU is fully scalable, allowing for a modular or permanent process configuration with many potential applications including field upgrading of bitumen from SAGD production; “straddle” conversion of diluted bitumen from export pipelines; integration with other upgrading or refining complexes; or large scale upgrading.

Preliminary cost estimates indicate that the technology compares favorably against delayed coking with lower capital costs and higher operating margins and is also conducive to relatively small scale applications.

Ceramatec tested the process on heavy oil, oil shale, and oil sands feedstocks with a wide range of densities, boiling curves, and sulfur, nitrogen, metals, and asphaltene contents. In nearly 6,000 hours of continuous operation, the process consistently removed sulfur and heavy metals. Nitrogen removal was also achieved, but not to the reduction levels of sulfur.

This new technology has the potential to increase feedstock value through direct quality improvements and through the reduced necessity for expensive capital processing equipment expansions at refineries, such as fluid catalytic crackers and desulfurization units. Using methane as the process feed-gas has the added advantage of reducing the carbon footprint of oil-upgrading by avoiding emissions from steam methane reforming. The process also eliminates sulfur oxide emissions by erasing the need for conventional sulfur recovery processes.

Background. Heavy oil is crude oil that is viscous and requires thermally enhanced oil recovery methods, such as steam and hot water injection, to reduce its viscosity and enable it to flow. The largest US deposits of heavy oil are in California and on Alaska’s North Slope. Estimates for the US heavy oil resource total about 104 billion barrels of oil in place—nearly five times the United States’ proved reserves. In addition, although no commercial-scale development of US oil sands or oil shale has yet occurred, both represent another potential future domestic unconventional oil resource.

Specialized processing is often required both to upgrade unconventional oil resources for transportation to refineries and, at the refineries, to produce more useful end-products. Technologies that lower these processing costs can improve the economic competitiveness of unconventional oil resources and help bring more domestic oil to market.

Ceramatec was awarded a grant by the NETL to conduct a project titled: “Post Retort, Pre Hydro-treat Upgrading of Shale Oil”. The program began October 2009, and was completed September 2012. There were 2 primary areas of the technology development:

• A process was developed which utilized an alkali metal (sodium or lithium) in combination with limited hydrogen or methane to promote desulfurization, denitrogenation, and demetallization of shale oil or heavy oil streams not suitable for refining prior to treatment.

• An electrolysis process was developed to regenerate the alkali metal and separate sulfur and metals. Alkali metal conductive ceramic membranes were utilized in the electrolytic process.

After extensive testing, Ceramatec determined that sodium is the preferred alkali metal over lithium for several reasons:

1. Sulfur removed relative to moles of alkali metal was substantially greater with sodium;

2. Sodium regeneration from sodium sulfide using the sodium ion conductive Nasicon membrane requires less voltage and is therefore economically favored over lithium;

3. Nasicon membrane is more mature and stronger than the lithium ion conductive Lisicon membrane, therefore the membrane cost is expected to be more favorable; and

4. Sodium is less costly and more readily available compared to lithium.

While the testing clearly favored sodium over lithium, hydrogen was only slightly preferred over methane as the gas mixed with the alkali metal and oil feedstock. With everything equal, methane is preferred over hydrogen because of lower cost and lower carbon dioxide emissions.

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This will make good use of some methane that is being flared in oil fields because smaller processing units can also be used with wells with regular oils and add the methane to to fuels for lighter weight less costly feed to all oils with the now cheaper methane. Perhaps even coal coke or coal and methane can be mixed to make liquids. Every refinery should add this process immediatly to increase the automotive fuel supply with cheap natural gas. Even biomethane can be used which eliminates the need for bioethanol. ..HG..

There's little or no associated methane in the tar sands fields, but the use of electricity in this system for regeneration of the sodium may add to the arguments for using nuclear heat for SAGD.  A nuclear reactor produces steam much hotter than required for SAGD, allowing a topping cycle to produce electricity.  Electrolytic hydrogen for the upgrader completes the trifecta.

Will this process reduce the Tar Sands oil extraction and associated pipelines pollution foot print?

If it does, will burning fuels extracted from Tar Sands eventually have about the same pollution level as fuels from standard Oil wells?

It would depend where the process energy comes from, and if it is sequestered or not (deep tar deposits might lend themselves to storage of CO2 in the emptied inter-grain spaces).

Of course, the POU footprint would not be affected.

It might help reduce the price of gasoline.

Another very negative side effect from Heavy Oil (including diluted bitumen) refining, is the very complex important toxic residues (15% to 30% of total).

Those low cost residues, when used instead of coal, are often 2X to 3X more polluting. Detroit refineries, after a few months, already have huge stockpiles. Runoffs will probably pollute the adjacent waters.

If profit hungry power plants owners switch from dirty coal to super dirty lower cost heavy oil residues, (which may happen very soon to lower production cost and increase profits), emissions would rise in many countries and worldwide.

If you mean petroleum coke, by all means say so.

Ceramatec are the people behind the sodium sulfur 200 Wh/kg battery with their patented membranes, same as here. That didn't exactly pan out, it disappeared quietly and I couldn't find one word of information why. Who says this will not suffer the same fate?

Yes, petroleum coke is the name most commonly used. Cement factories have already started to use it with more negative environmental effects than expected.

Refiners are actively looking for daring customers for those low cost heavy oil residues or embarrassing petroleum coke.

Direct and indirect 'downstream, pollution from current and future (very) low price 'petroleum coke' have not yet been fully considered (counted) in USA and Canada total emissions.

As more and more heavy oil will be refined in the future, one may not be surprised if 100+ dirty coal fired power plants progressively switch to much low cost dirtier 'petroleum coke' to increase their profit margins.

A few politicians may object put a few M will keep them at bay and/or convince them that is the best way to go to get rid of the fast growing 'petroleum coke' stock piles.

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