ZEST (Zero Emissions SAGD Technology) Processes

Upgrade SAGD Bitumen and Avoid CO2 Taxes with Very Short Simple Payout



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How the BEST®¹ Asphaltene Removal Process Works With a SAGD Facility



  1. Water is separated from the oil produced by SAGD.
  2. The water is recycled back to the Steam Generators to be turned back into steam.
  3. Asphaltenes are removed from the oil produced making it far more valuable.
  4. The asphaltenes are used in the Steam Generators instead of natural gas.
    • The Steam Generators are operated at high enough pressure so that the water produced by combustion can be used as injection steam.
    • Recycled water is injected into the steam generators to keep the combustion temperature within reason.
  5. All of the flue gas and steam from the combustion is sent to the SAGD Injection wells.
    • The CO2, SO2, and NO2 from the flue gas will not condense in the reservoir but rise above the steam and likely dissolve in additional oil within the reservoir that the steam could not reach.
    • If CO2, SO2, or NO2 come out dissolved in the bitumen it is re-injected.
  6. Less diluent is needed to meet pipeline specifications with the deasphalted bitumen.
  7. The deasphalted bitumen is worth more than the bitumen because all of it can be converted into usable products.
  8. Asphaltenes cannot be converted into usable products. They only have fuel value less flue gas clean-up costs.




  • No Natural Gas Required unless high steam to oil ratio
  • Less diluent Required
  • No Greenhouse Gases Emitted
  • Deasphalted Bitumen is more valuable than Bitumen

¹     BEST Asphaltene Combustion is a registered trademark of Brighton Engineering Solutions Ltd.


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BEST™¹ Processes Can Make SAGD More Profitable


As the table above shows MEG Energy, or any other SAGD Producer can increase profits by ~$27.58/bbl, in 2017, by using our technology with Athabasca Bitumen, and about the same amount with Cold Lake Bitumen or Peace River Bitumen.

  1. Making clean Alberta Deasphalted Bitumen, without greenhouse emissions should clean up Alberta Oil’s negative image outside of Alberta.
  2. Removing the asphaltenes makes bitumen worth about 97% as much as WTI.
  3. Removing the asphaltenes decreases your diluent requirements by 54%.
  4. Not shipping the asphaltenes and the extra diluent required cuts your transportation costs by 61%.
  5. Burning the asphaltenes gets fuel value for the asphaltenes and eliminates your natural gas purchases for an equivalent heat content.
  6. Co-injecting the flue gas with the steam or under a salt water aquifer, without a compressor eliminates your greenhouse gas emissions.

¹     BEST Processes is a trademark of Brighton BEST Dynamics Ltd.


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Removing 87 kg of CO2 from SAGD Production decreases In Situ total COby 16.6% and makes it 12.4% less than Average US Barrel


Simply using the BEST™¹ Processes to remove the CO2 from production makes Alberta In-Situ Bitumen 12.4% lower than the Average U.S. BARREL REFINED IN THE U.S. (2005).   87 kg/bbl is the average SAGD CO2 Production.  Therefore pipelining the diluted bitumen adds another 38 kg of CO2 per barrel of bitumen.  The technology is already available from us to eliminate the SAGD production CO2.  If the pipeline uses solar, wind, hydro, nuclear, or BEST®¹ Asphaltene Combustion Unit generated power to transfer the diluted deasphalted bitumen, that takes off 125 kg/CO2/bbl making diluted deasphalted bitumen 20% lower than the average U.S. Refined Barrel.  Environmentalists will be begging for more diluted deasphalted bitumen to be sent to the US.

 ¹     BEST Asphaltene Combustion is a registered and BEST Processes are trademarks of Brighton BEST Dynamics Ltd.

How Much Are Your Asphaltenes Really Worth?


Based on what MEG Energy claimed they were getting for their Bitumen Realization for 2016, and what I know the deasphalted bitumen is worth from their SAGD Production, 17.3 vol% of their production must be worth -$77.08 per barrel.  Based on the fuel value of the asphaltenes and the cost of fuel from natural gas, the asphaltenes are worth $17.19 per barrel if you do not have to pay for flue gas cleanup.  With the BEST®¹ Asphaltene Combustion Process, you do not have to pay for any flue gas cleanup and the water by-product of combustion decreases your make-up water.  $94.27 per barrel is how much more the asphaltenes are worth to the SAGD Producer than they are worth to a refiner, so why ship them to get so much less for them.

¹     BEST Asphaltene Combustion is a registered trademark of Brighton BEST Dynamics Ltd.


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Economic Incentives Very High for Installing BEST™¹ Processes at SAGD Facility


With thanks to the “Partial Upgrading Background Review – In Support of the National Partial Upgrading Program” for the graph above, I was able to put the BEST™¹ Processes into the graph.  As you can see, the BEST™¹ Processes are 4-6 times better than anything evaluated by the program.  The reason is very simple, deasphalted bitumen is no longer crude oil and should not be evaluated as such.  It is perfectly good feedstock for a catalytic cracker feed hydrotreater and a middle distillate hydrotreater, or if you prefer, a hydrocracker feed hydrotreater and a middle distillate hydrotreater.

¹     BEST Processes is a trademark of Brighton BEST Dynamics Ltd.


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Properties of Hydrotreated Deasphalted Vacuum Resid from 2 out of the 3 Alberta Bitumens


I just thought you might like to see what happens to the 565.5°C portion of 2 out of 3 the Alberta Deasphalted Bitumens in a typical Catalytic Cracked Feed Hydrotreater.  Having spent time in Exxon as their Resid Catalytic Cracking guru, I would divide the CCR (now MCR) value by 3 (W. R. Grace a Catalytic Cracking Catalyst vendor claimed you should take the cube root of the MCR in deasphalted oils) and this would be a wonderful Catalytic Cracker feedstock.

Unocal stated that “In each case the projected cycle length is far greater than one year.” and this was for the 565.5°C+ fraction of deasphalted bitumen. The US EPA rules and regulations required nearly every refinery to install a Catalytic Cracker Feed Hydrotreater.  The one in Cheyenne, Wyoming was operating at the same hydrogen partial pressure as the one in Case 1 of that paper.  When I told the Refinery Manager that he said if you can get deasphalted bitumen vacuum resid here, we would run it.


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Why Refineries Do Not Like Asphaltenes?


For anyone that has worked in a refinery, they know that asphaltenes are notorious for fouling heat exchangers.  Having spent a good portion of my career removing asphaltenes from vacuum and atmospheric residue, I can tell you why the above pictured problem occurred.  Asphaltene containing streams should always be on the tube side of any heat exchanger, unless you are cross exchanging two stream containing asphaltenes.  In that case the lowest asphaltene containing stream should be on the shell side, or you can use a spiral heat exchanger. It also helps to keep the asphaltenes well above their Ring & Ball Softening Point.  Obviously from the asphaltenes left on the heat exchanger tube bundle, whoever designed this plant did not know how to handle asphaltene containing streams.

Having designed the OrCrude™¹ Facility in the CNOOC/Nexen Upgrader, one could say that I know how to handle asphaltene containing streams and streams that only contain asphaltenes.  Who else would be willing to stake their reputation on deasphalting bitumen at the SAGD facility so that the SAGD Operator could get full value for their production and the asphaltenes can be burned to make steam.

¹     OrCrude is a trademark of Ormat Technologies, Inc.


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Designing a Carbon-Neutral SAGD Facility


Anna Giove of Oil Sands Magazine has written an article about how our technology impacts on and can enhance the SAGD Process.  I encourage you to view Anna’s article.  It is at http://www.oilsandsmagazine.com/news/2017/3/20/driving-towards-zero-a-calgary-firm-takes-on-the-challenge-of-designing-a-carbon-neutral-sagd-facility, and will be in the Friday, March 24, 2017 issue of Oil Sands Magazine.  The figure above was taken directly from the article.


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