Driving towards zero: A Calgary firm takes on the challenge of designing a carbon-neutral SAGD facility

Driving towards zero: A Calgary firm takes on the challenge of designing a carbon-neutral SAGD facility

Aside from low oil prices, there's no question Alberta's oil sands face numerous headwinds.

Production growth over the next decade will undoubtedly be led by the SAGD operators. Although they have the advantage of being much lower capital than mining, in-situ facilities rely on large volumes of steam, generated by burning natural gas. And that translates into higher carbon emissions per barrel of oil produced.

The NDP government's 100 Mt/year emissions cap means that bitumen production, under the current technology, obviously can't grow to the sky. By all accounts, Alberta will hit its emissions cap in less than 10 years, leaving many to ask the question - then what? The provincial government has pulled together a task force to help answer that question, but it's obvious a major shift in technology is required.

But carbon isn't the only headwind.

Bitumen produced from SAGD wells is heavy and sour, requiring large volumes of diluent, typically condensate, to meet pipeline specifications. Most of that diluent is purchased at prices very close to WTI. The large volumes of diluent used in the oil sands not only drives up the price but also takes up precious pipeline capacity, in some cases as much as 40%. 

Heavy sour bitumen from the oil sands has a limited market - mostly high-conversion refineries in Houston and Chicago. Although both are very large customers, they are a considerable distance from Alberta's industrial heartland. Coupled with major pipeline constraints, the long distances drive up the cost of transport, forcing Alberta's bitumen to sell at a discount to comparable heavy crudes from around the world.


Although some may feel discouraged, a Calgary consulting firm is tackling these challenges head on. Brighton Engineering Solutions is an engineering and research agency servicing the global energy sector since 1988. The team has over 25 years of experience spanning four continents and now wants to take on the challenge of designing a more profitable SAGD process, with a much lower carbon footprint.

  • lower for longer oil prices
  • pipeline constraints
  • high cost of imported diluent
  • limited marketability
  • carbon tax adding $50/t by 2022
  • 100 Mt/yr carbon cap reached in 2023


Alberta's bitumen contains on average about 20% asphaltenes. Asphaltenes are heavy, highly complex hydrocarbon molecules that make bitumen sticky, viscous and almost rock-solid at room temperatures. That's partly why bitumen produced from the oil sands requires such huge volumes of diluent.

The team at Brighton believe that removing asphaltenes is the key to unlocking more value out of every barrel. As a stand-alone product, asphaltenes have very limited economic value. However, these heavy bottoms can be burned to produce fuel and power.


Brighton's Chief Technology Officer Richard Hood and his team have developed a process that takes diluted bitumen from the oil sands, strips out the diluent, removes the asphaltenes and burns those asphaltenes for power and steam. Flue gases from asphaltene combustion are injected back into the SAGD wells along with the steam. The end result is a more marketable deasphalted bitumen, requiring less diluent for transport and only a nominal amount of natural gas. Best of all, the carbon footprint of bitumen production could be reduced to almost zero.


Large volumes of diluent are used in SAGD facilities to clean-up the bitumen/water emulsions pumped out of the production wells. The diluent portion of the diluted bitumen is first recovered through a pair of flash columns installed in series. The diluent vapours are then condensed and recycled back to the bitumen processing plant, leaving behind a hot bitumen product with about 20% asphaltenes.

The heavy asphaltenes are then removed from the bitumen through a modified pentane deasphalter. Asphaltenes are insoluble in pentane, forcing the heavy complex compounds out of solution. The deasphalting unit produces two streams - asphaltenes and deasphalted bitumen, both containing generous volumes of pentane (or solvent) that need to be recovered.

Both the asphaltenes and deasphalted bitumen are processed through strippers to remove and recover the pentane, which is recycled back to the deasphalting unit. A debutanizer removes any undesirable light-ends from the solvent, keeping the pentane relatively clean. Any required volumes of make-up pentane can either be purchased on the open market, or preferably be produced on site through fractionation of the diluent stream.

Once the solvent is removed from the bitumen, diluent is added to meet pipeline specifications before the product can be sold to market. Since the bitumen is now mostly deasphalted, diluent requirements are cut in half.

The solvent-free asphaltenes can then be combusted through the addition of supercritical (or liquid) oxygen. Steam is added to disperse the hot liquid asphaltenes for rapid, full combustion. Boiler feed water is used as a quenching medium, producing high-pressure steam for the SAGD wells and processing plant.

Unlike partial residue combustion that typically occurs during gasification, full combustion doesn't produce any hydrogen or carbon monoxide. The company's combustion process produces a flue gas containing mostly carbon dioxide and steam. This flue gas can be co-injected into the SAGD wells or sequestered under salt-water aquifers. SaskPower has been pumping CO2 into oil reservoirs since the year 2000, proving that carbon can safely be injected underground or even be used to enhance heavy oil recovery.

  • diluent requirements cut in half
  • freed up pipeline constraints
  • better quality refinery feedstock
  • improved marketability
  • minimal natural gas requirements
  • lower carbon footprint


Removing asphaltenes lowers the density and viscosity of the bitumen, cutting diluent requirements in half. That frees up space on the pipeline and lowers transportation costs.

Since asphaltenes are burned to produce power and steam, natural gas is no longer required. Any excess steam produced during combustion can be used to generate power and sold to Alberta's electrical grid.

Aside from making the crude less heavy, removing asphaltenes also knocks-out most of the nickel, vanadium and carbon residue contained in the bitumen and a good fraction of the sulphur. A bitumen product void of asphaltenes makes excellent refinery feedstock. Removing the heavy bottom components of the crude allows the remaining bitumen to be fed directly to the catalytic cracker or hydrocracker after hydrotreating. And that translates into a better quality product with improved marketability and higher sale price.

Of course, no process is without its drawbacks. Burning asphaltenes reduces product yield, since a portion of the bitumen is burned for energy. But netbacks can be significantly improved through savings in diluent purchase, bitumen transport costs, higher bitumen realization prices and savings in natural gas. And that all translates into improved profitability for the operator.

Best of all, the PR benefits of a bitumen product with zero upstream carbon emissions could be priceless.

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