Heavy Oil And Bitumen - Not Glamorous, But Often Profitable
Authors: Miller Karl A. 
Published: March 2010

The terms heavy oil and bitumen are often used in the Canadian oil industry because of their significant share of total current production and the huge volume of in-place resource (Figure 1 and Table 1). Despite this high profile, many facets of heavy oils and bitumens are not well known.

What are Heavy Oils and Bitumens?

Historically the term heavy oil has been used to describe oil that is more dense and viscous than conventional oil. This imprecise definition is hard to apply, and in 1982 a committee of UNITAR(a) delegates created a two step classification process(1). First, materials with gas-free viscosity greater than 10,000 mPa.s (cp) at reservoir temperature are classified as immobile bitumen. Next, density is used to sub-classify oils with viscosities of 10,000 mPa.s or less (Table 2).

A number of Canadian oils with viscosities over 10,000 mPa.s can be economically cold produced, so I asked one of the attendees how UNITAR's immobile bitumen criterion was obtained. He replied that the committee found the task very challenging, and accepted a compromise value so they could adjourn and go sightseeing in Caracas.

UNITAR's efforts helped establish the range of properties exhibited by heavy oils and bitumens, but their method of classification has not been universally adopted. Neither Alberta's ERCB nor Saskatchewan's SEM use it for royalty calculations, nor do their definitions agree. So, when you encounter the terms heavy oil or bitumen, be prepared to spend the time required to ensure the material's properties match your definition.

FIGURE 1: Principal heavy oil and bitumen sandstone deposits of Western Canada (after Allan and Creaney, 1991). (Available in full paper)

How did it Become Heavy Oil or Bitumen?

According to recent literature(2–6) the process took several steps. First the reservoir minerals were carried by water flowing from the Precambrian Shield on the east and more varied terrains to the north and south. The sands(b) were deposited in a variety of deltaic to near shore environments, in forms ranging from thin sheet like regional sands to narrow but thick channel sands. The resulting reservoir quality is generally very good to excellent, with porosities exceeding 30% and Darcies of permeability.

Prior to oil migration, a regional anticlinal trap was formed by water dissolution of underlying salt deposits. Localized traps were formed by shale filled channels. Reservoir dip is generally small, and both flank water and bottom water are common features. At least four separate organic rich source rocks on the west side of the Western Canada Basin were buried to increasing depths by plate collisions during formation of the Rocky Mountains (the Laramide Orogeny). As oils were generated, they migrated upward in a northeasterly direction until encountering the described traps.

The oils contacted fresh water entering the basin from outcrops along the northeastern edge (Figure 2). Bacterial action, water washing, and oxidation removed the light organic components leaving a heavy oil or bitumen residue. Oil density is likely proportional to localized cumulative fresh water exposure [see Figure 6 of Reference (3)].