Novel Desulfurization May Boost Refiner, Oil-sand Production Values


Downstream Business - (Dec 3, 2014)

Alberta-based Field Upgrading is touting a molten-sodium crude desulfurization and demetallization scheme that not only could slash the cost of refinery processing of oil-sands crudes—and simultaneously boost the producer value of such crudes—but also could deliver more supplies for the burgeoning low-sulfur marine bunker-fuel markets.

Asked for more details about the scheme, Field Upgrading business development vice-president Mike Doma told Hart Energy’s ( the following: Do you imagine that some companies would invest in this scheme at a greenfield, stand-alone site, presumably at an oil-sands production site? What sort of company would be a likely candidate to invest in this?

Doma: At its core, the technology is, in our opinion, very efficient at removing sulfur, metals and acids from heavy oils, bitumen, vacuum residue and other refinery intermediate streams. Some moderate upgrading also occurs from this process as the sulfur is removed.

For example, we typically see an 8- to 10-degree API boost for product with 5% sulfur. The viscosity reduction is typical of what can be expected with that type of change in API.

The two broad applications we see for this technology then are: first, heavy oil or bitumen upgrading to produce a heavy, low-sulfur, low-TAN [total acid number] crude oil; and second, desulfurization and upgrading of vacuum residue to 0.5%- or 0.1%-sulfur residual fuel oils.

We anticipate the heavy oil or bitumen upgrading applications to be more likely [developed] as a greenfield build at an oil production site, and the residue upgrading a brownfield application at a refinery.

Other potential refinery applications include the treatment of intermediate refinery streams for sulfur and metals removal [e.g., light-oils sulfur reduction to parts-per-million levels, metals and sulfur removal from residues for FCC [fluid catalytic cracker] feed or coker feed].

There is also a midstream application where a bunker fuel oil supplier could build at an existing site and source various feedstocks [e.g., refinery residues, high-sulfur residual fuel oil] to produce low-sulfur residual fuel oils. Our goal is to have commercially viable plants at a scale of 1,000 barrels per day—our modular building-block size—which could make it well-suited for these applications. Could this scheme just as well be accomplished at an existing oil refinery, with additional investment in your proposed process units?

Doma: As mentioned, there are many applications for the technology at an existing refinery and there will be synergies derived from these brownfield installations. Your scheme requires a source of hydrogen. Hydrogen is already available at existing oil refineries. So wouldn't it be difficult to undertake your scheme at a site that lacks hydrogen supplies?

Doma: For a 5% sulfur feedstock, we require about 500 standard cubic feet per barrel of hydrogen. Some refiners may have incremental hydrogen production capacity available or there may be hydrogen available for purchase from third parties.

Incremental hydrogen can also be produced through steam methane reforming. Our process does not form hydrogen sulfide [H2S], and therefore would not require incremental capacity for sulfur recovery and tail gas

treating. Similarly, we do not expect any material increase in sulfur-oxides [SOX] emissions in adding this process. Would selling low-sulfur bunker fuel [<0.5% or <0.1%] be the most profitable product from this scheme? Or would it instead make more sense to sell this mostly-desulfurized fuel oil to an existing oil refiner, who could further process this feedstock into [for example] higher-value, ultralow sulfur diesel [ULSD] or kero- jet fuel?

Doma: We believe that all of these areas could be profitable applications of the technology. Certainly with the changes coming to the sulfur specification for bunker fuel oils [<0.5% or <0.1% sulfur] and the high cost alternative for that industry to consume low-sulfur distillates, the margin available to go from high- sulfur vacuum residue to a low-sulfur residual fuel oil could be quite large. We also see good economics in taking high-TAN, high-sulfur, 8-degree API bitumen to a heavy, sweet, low-TAN crude oil. Depending on the refinery, we also expect good economics for some niche sulfur and metals removal applications.

Process description

According to Field Upgrading, the heavy-oil desulfurization-upgrading (DSU) process yields 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.

“DSU 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.

“The pipeline-ready DSU 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,” according to the company.

The “core technologies” for the process are based upon “oil industry experimental work paired with [Utah-based] CoorsTek ceramic ionic conductor technology,” according to the company.

“Sodium, along with small quantities of hydrogen or methane, is mixed with bitumen to break down the bitumen molecule by precipitating metals and preferentially seeking out and removing sulfur and nitrogen as salts,” according to Field Upgrading.

This is followed by “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.”

Finally, the third step is: “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 ionically through the membrane and recycled to the process. The remaining product is elemental sulfur,” according to the company.

Field Upgrading is now building an $18 million, 10 barrel-per-day pilot plant, with “private and government funding in place,” according to the company.

Tests so far have demonstrated capacity to desulfurize a 6%-sulfur resid to ISO- specification bunkers with <0.5% sulfur—the 2020 global sulfur limit under pending International Maritime Organization bunker-fuel legislation.

The scheme is also “expected to desulfurize 2%-sulfur resid to ISO-spec bunkers with <0.1% sulfur,” which is the sulfur limit for “emission-control areas” that so far include North America and parts of Europe, but also possibly spreading to Asia.

A 50,000 tonne-per-annum DSU demonstration plant is forecast to start-up by 2018, with commercial-scale plants debuting thereafter, according to the company.

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