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Froth Treatment Explained

Froth Treatment Explained

Froth Treatment is a process by which water and fine solids are removed from bitumen froth using hydrocarbon-based gravity separation. There are two different types of hydrocarbons used in Froth Treatment: a naphtha-based hydrocarbon and a lighter paraffinic solvent. Both produce a relatively clean bitumen product but only a paraffinic process produces a marketable product stream.

In an oil sands mining facility, the froth produced in Extraction is only 50 to 60% bitumen with a relatively high concentration of fine solids (up to 15%) and can contain as much as 40% water. This bitumen froth is further processed in Froth Treatment where water and solids are removed using a solvent or light hydrocarbon. This hydrocarbon greatly reduces the viscosity of the bitumen and enables a more effective gravity separation of the various phases.

The Froth Treatment facility produces a final product with a relatively low water and solids content, typically less than 2%. Depending on the quality of the product, the bitumen can either be sent to an upgrader for conversion to synthetic crude oil or diluted and sold directly to refineries that have the ability to process heavy oil.

PROCESS OVERVIEW

Bitumen froth produced in Extraction contains about 60% bitumen, 30% water and 10% fine solids. This product requires further cleaning before the bitumen can be upgraded to crude oil or sold to market. Since no further cleaning can occur by water-based gravity separation, a light hydrocarbon is added to the froth in order to reduce the viscosity of the bitumen and enable a more effective gravity separation. This process is typically referred to as Froth Treatment.

Froth Treatment can be broken down into 4 basic steps:
  1. Add an appropriate amount of light hydrocarbon to the bitumen froth and mix thoroughly.
  2. Gravity separate the water/solids (tailings stream) from the bitumen/hydrocarbon mixture (product stream).
  3. Recover the hydrocarbon from the bitumen/hydrocarbon mixture and recycle the hydrocarbon back to the the front end of the process (as per Step 1). The clean bitumen product that remains can then be upgraded into crude oil or diluted and sold to market.
  4. Recover the hydrocarbon from the tailings stream and recycle the hydrocarbon back into the process. Froth Treatment tailings are then be stored in a tailings pond for future reclamation.

HYDROCARBON-BASED GRAVITY SEPARATION: WHY WATER ISN'T ENOUGH

Mined oil sands is comprised of 4 basic components: bitumen, water, coarse sand and fine solids.

After the oil sands is slurried with water, water-based gravity separation is used to remove the coarse sand, leaving an intermediate bitumen froth product. The composition of this froth is typically as follows (by weight):

  1. Bitumen: 50-60%
  2. Water: 30-40%
  3. Fine Solids, including clays: 10-15%

The froth therefore needs another cleaning step before the bitumen can be upgraded or refined. 

Bitumen froth acts almost like a single-phase fluid. The water and bitumen are closely intermixed, with fine solids trapped within the viscous mixture. Since the density of bitumen and water are both very close to 1.0, they can not be separated by gravity, no matter how much residence time is provided in Extraction. 

AVERAGE DENSITIES (SG):
Water ≈ 1.0
Bitumen ≈ 1.0
Fine Solids/Clays ≈ 2.65
Solvent/Diluent ≈ 0.6 - 0.8
Diluted Bitumen ≈ 0.8 - 0.9

In order to separate the bitumen from the water and solids, the density and viscosity of the bitumen must be lowered. This is accomplished through the addition of a light hydrocarbon, typically referred to as a solvent or diluent. This hydrocarbon dilutes the bitumen, producing a less viscous, lighter product, with a density lower than water. The viscosity of the diluted bitumen also drops significantly, which releases the trapped fines. The diluted bitumen can now float to the top of the gravity separation vessel, leaving the fines to settle to the bottom of the water phase.

BITUMEN FROTH: 3 KEY FACTS

  1. Bitumen mined from the Athabasca Basin contains about 18% asphaltenes, which are sticky, high molecular-weight compounds, with a complex aromatic ring structure. Asphaltenes impart a high viscosity to the bitumen. They are not dissolved but instead exist in a colloidal suspension. Asphaltenes are soluble in aromatic compounds (such as benzene) but will precipitate in the presence of light paraffinic solvents, such as pentane.
  2. At least half of the fine solids contained in the bitumen froth are clays, which are defined as ultrafine particles sized less than 2 μm. Clays found in oil sands deposits are mostly comprised of kaolinite and illite. Clay platelets tend to attach themselves to the bitumen and make bitumen recovery more difficult.
  3. Bitumen froth contains emulsions of water and bitumen, which are stabilized by the clays and the natural surfactants found in the bitumen (attributed to the high asphaltene content). These emulsions are very stable, making it very difficult to remove the water and fines from the bitumen, unless very high g-forces are applied or the asphaltenes are precipitated.

NAPHTHENIC VERSUS PARAFFINIC SOLVENT: WHAT'S THE DIFFERENCE?

The key to Froth Treatment is the type of light hydrocarbon used as the solvent/diluent. There are 3 types of naturally occurring hydrocarbon compounds, classified according to their molecular structure:

  1. Paraffins: straight chains or branched chains of carbon atoms, also known as alkanes. Paraffins are saturated hydrocarbons where each H atom is joined to a C atom and have the chemical formula CnH₂n+2.
  2. Naphthenes: saturated hydrocarbon compounds arranged in the form of closed rings (cyclic) with a chemical formula CnH₂n. Naphthenes are very stable and are sometimes referred to as cycloparaffins or cycloalkanes.
  3. Aromatics: unsaturated hydrocarbons (hydrogen deficient) with ring-type (cyclic) compounds, consisting of at least 1 benzene ring.
← MORE PARAFFINIC
MORE AROMATIC →
lower density
lower viscosity
lower boiling point
asphaltene precipitation
higher density
higher viscosity
higher boiling point
asphaltene dissolution
Examples of Paraffinic Compounds:
  Compound Formula B.P. SG*
  butane C4H10 0°C gas
  pentane C5H12 36°C 626
  hexane C6H14 69°C 659
  heptane C7H16 98°C 684
 *Specific gravity measured at 20°C
Examples of Aromatic Compounds:
  Compound Formula B.P. SG*
  benzene C6H6 80°C 884
  toluene C7H8 111°C 872
 
       
 *Specific gravity measured at 20°C

The solvents/diluents used in Froth Treatment are a complex mixture of hydrocarbons. Since the primary objective of Froth Treatment is to lower the density and viscosity of the bitumen phase, aromatics are generally considered undesirable. Therefore, paraffinic and naphthenic solvents are used, with as little aromatics as possible. Solvents containing primarily paraffin hydrocarbons are called paraffinic. Solvents containing primarily naphthene hydrocarbons are called naphthenic.

The choice between a naphthenic or paraffinic solvent used during Froth Treatment depends on the desired product quality. Solvents that contain more paraffins produce a cleaner bitumen product than solvents that contain more naphthenes. 

WHY PARAFFINIC SOLVENTS PRODUCE A BETTER QUALITY BITUMEN PRODUCT

The presence of asphaltenes in the bitumen stabilize the water/solids/bitumen emulsions, making it difficult to produce a good quality product unless the asphaltenes are simultaneously precipitated. Since asphaltenes are insoluble in the presence of paraffins, a paraffinic solvent encourages asphaltene precipitation. As the asphaltenes precipitate and agglomerate, they bind with the water and solids, producing a bitumen product virtually free of water and solids. Another beneficial side-effect is the partial removal of the heavy asphaltene fraction (up to 50%), which now makes the bitumen saleable directly to refineries that have the capacity to process heavy/sour crude. These high-conversion refineries convert the partially de-asphalted diluted bitumen into marketable products without an intermediary upgrading step.

As the carbon number of the solvent increases (eg. C7 heptane versus C5 pentane), more solvent is required to precipitate asphaltenes out of solution.
A more aromatic solvent increases the solubility of asphaltenes. As aromaticity of the solvent decreases (i.e., more paraffinic), more asphaltenes will precipitate.

Although it is possible to precipitate asphaltenes with a naphthenic solvent, it would require a much higher fraction of solvent. Precipitation of asphalenes is much more easily achieved with paraffinic solvents that have a lower carbon-number (such as pentane and hexane).

NAPHTHENIC VERSUS PARAFFINIC: KEY DIFFERENCES

Although the basic concept of hydrocarbon-based gravity separation is the same in both cases, there are subtle difference between the Froth Treatment processes that dramatically changes the plant design and final product.

NAPHTHENIC FROTH TREATMENT (NFT)

  • uses a higher density, more viscous naphthenic hydrocarbon, typically referred to as naphtha or diluent
  • no asphaltenes are precipitated in the process, leaving the bitumen asphaltene content unchanged at about 17-18%
  • more bitumen/water/solids emulsions are formed, requiring more equipment and higher g-forces to separate the 3 phases
  • bitumen product typically contains about 98% bitumen, with 2% water + solids remaining in the product
  • bitumen product requires an intermediary upgrading step to remove the remaining water/solids and heavy asphaltenes before refining.

PARAFFINIC FROTH TREATMENT (PFT)

  • uses a lighter, less viscous paraffinic hydrocarbon, typically referred to as solvent
  • about 50% of the asphaltenes will precipitate in the process, reducing the bitumen asphaltene content to less than 10%
  • fewer emulsions formed due to asphaltene precipitation, making separation more efficient and requiring less equipment
  • final bitumen product is quite clean, typically 99.9% bitumen containing less than 0.1% water + solids
  • the bitumen product can now be sold directly to a high-conversion refinery without an upgrading step.

A BRIEF HISTORY OF FROTH TREATMENT IN THE OIL SANDS

The original Suncor and Syncrude operations use a naphtha-based Froth Treatment process. The bitumen product from these facilities contains approximately 1% water and less than 1% solids. This bitumen is then processed in an adjacent upgrader, where it is converted to synthetic crude oil (SCO). SCO is sold on the open market and purchased by refineries, which convert the crude oil into final consumer products, such as gasoline, diesel and jet fuel.

Construction of the Muskeg River Mine in 2001 marked a step-change in Froth Treatment technology. In an effort to reduce capital costs, majority owner and operator, Shell Canada, was determined to build its upgrader adjacent to its Scotford Refinery near Edmonton, 300 km away from the mine site. The upgrader was intended to use high conversion hydrogen addition, which eliminates the need for cokers. This required Muskeg River to produce a better quality bitumen that could be pumped the 300 km distance from Fort McMurray to Fort Saskatchewan, Alberta. A conventional naphtha-based Froth Treatment process would not work for Shell. The resulting bitumen product would contain too much water and solids and could not feasibly be pumped a long distance due to erosion/corrosion concerns in the pipeline. The relatively high asphaltene content of the bitumen (near 17%) would also be too high for the upgrader to handle.

Muskeg River therefore chose to build a paraffinic Froth Treatment process (PFT), becoming the first commercial operation to use PFT. PFT technology was patented by Syncrude in 1994 but use rights were made available to all other oil sands operators. PFT produces a much better quality bitumen, bringing the water and solids content to virtually zero and reducing the fraction of heavy asphaltenes. The partially de-asphalted bitumen could now be pumped the long distance to Edmonton.

The Horizon Mine began construction shortly after Muskeg River. Horizon chose to use a naphtha-based Froth Treatment technology adopted from the Suncor process. Since Horizon was intended to be built with an on-site upgrader (equipped with cokers), there was no need to build a more expensive PFT facility. The lower quality bitumen produced by the naphthenic Froth Treatment facility is converted to high-quality SCO by the adjacent Horizon Upgrader before being sold to market.

The Kearl Oil Sands Mine was the next facility to be built, and was likely the very first oil sands mine that was never intended to be coupled with an upgrader. Much like Muskeg River, Kearl uses PFT technology to produce a high-quality, partially de-asphalted diluted bitumen, which is good enough to be sold directly on the open market. This diluted bitumen stream can then be purchased by high-conversion refineries that have the capacity to process heavy/sour crude.

The Fort Hills Mine also employs PFT technology to produce a high-quality diluted bitumen sold directly on the open market without needing to be being upgraded.

BITUMEN PRODUCT SPECS: WHY WATER AND SOLIDS ARE BAD

As a general rule, it is desired to have less than 0.5% mineral solids and water and a viscosity less than 350 cP before the crude oil stream can be transported on a third-party pipeline. Since NFT cannot easily meet those specifications, an on-site upgrader is required to meet the lower water, solids and viscosity targets. A PFT process can easily meet the water/solids specification, but viscosity targets can only be achieved by adding a sufficient amount of diluent before being sold to market (about 30% by volume). Diluents used in the oil sands typically consist of natural gas condensate, refinery naphtha and other light hydrocarbons.

Regardless of the process used, water and solids have a very harmful effect on downstream process, whether it be upgrading or refining. Fine solids contained in the bitumen poison the hydroprocessing catalyst, reducing its effectiveness. Water carries with it a significant concentration of dissolved salts, mostly in the form of sodium chloride, which causes serious corrosion problems.

UPGRADING VERSUS REFINING

Conventional refineries cannot handle feedstock with a high water and solids content due to severe corrosion caused by the chlorides and salts contained in the water. Athabasca bitumen contains a large fraction of heavy ends, such as asphaltenes which promote severe fouling during precipitation.

That's why bitumen produced from the oil sands was traditionally upgraded, before being processed through a refinery. The purpose of upgrading is primarily to reduce the heavy hydrocarbon fraction of the bitumen (including the asphaltenes) through a process known as coking, producing a light synthetic crude oil product that can be sold to a conventional refinery. Upgraders also remove sulphur, which is naturally occurring in the oil sands deposit and reports with the bitumen product.

Oil sands mining facilities equipped with PFT precipitate about 50% of the heavy asphaltenes contained in the bitumen, removing virtually all of the water and solids in the process. This partially de-asphalted bitumen product can now be sold directly to high-conversion refineries which converts the heavy oil to final marketable products without the need for an intermediary upgrading step. These refineries can handle feedstock with some fraction of asphaltenes, as long as most of the solids and water are removed. Note that sulphur content is unchanged regardless of the froth treatment technology used.

Primary Separation Cells

Primary Separation Cells

Paraffinic Froth Treatment

Paraffinic Froth Treatment

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