Products from the Oil Sands: Dilbit, Synbit and Synthetic Crude Explained
Bitumen produced from the oil sands contains a significant fraction of complex long chain hydrocarbon molecules known as asphaltenes. These highly complex molecules make the bitumen sticky, viscous and almost rock-solid at room temperatures. Asphaltene content can vary from 10% to over 20%, depending on reservoir geology.
Alberta's bitumen also has a relatively high sulphur content, as much as 5%. Aside from contaminating the final products, sulphur is extremely detrimental to downstream refining equipment and can poison the catalyst during catalytic reforming.
Due to the high fraction of heavy components and high sulphur content, bitumen produced from the oil sands cannot be sent directly to a conventional refinery. Conventional refineries (sometimes referred to as "simple topping" refineries) are designed for a light, sweet (sulphur-free) feedstock. A lower quality heavy bitumen product must therefore be upgraded into a light crude oil, removing most of the sulphur before it can be sold to a conventional refinery. Upgraded bitumen is known as synthetic crude oil (SCO).
Better quality bitumen with a relatively low water and solids content and less than 10% asphaltenes can be diluted and pipelined directly to high-conversion refineries which have the capacity to accept a heavier crude oil feedstock with a high sulphur content.
High-conversion refineries are much more complex than conventional refineries. These facilities have integrated "upgrading" equipment that crack and coke the heavy bottom fraction of the bitumen into lighter crude and remove all traces of sulphur.
In order to meet pipeline specifications, diluted bitumen sold to market (commonly referred to as Dilbit) must contain less than 0.5% water + solids and have a minimum viscosity of 350 cSt (or a maximum density of 940 kg/m³). These specifications ensure the crude will flow at low temperatures, and minimizes the risks of corrosion and erosion.
Since pure bitumen is so viscous, significant volumes of diluent are added in order to meet these pipeline specifications. Natural gas condensate is the most common diluent stream, although refinery naphtha or any light sweet crude can also be used.
Any bitumen that does not meet these specs cannot be pipelined very far and is usually processed at an on-site upgrader. Upgraders crack (break down) and/or coke (remove) the heavy bottom components of the bitumen through fractionation and chemical treatment, producing a lighter, less viscous crude with very little sulphur. Once the bitumen is upgraded, it can then be sold via pipeline on the open market.
BITUMEN, DILBIT, SYNBIT AND SYNTHETIC CRUDE
It's important not to get lost in the terminology. In order to get a product to market, it must meet pipeline specifications. In order to meet pipeline specifications, operators blend a variety of crude streams.
Bitumen is the hydrocarbon component contained within the oil sands and the most commonly referenced "oil" from Alberta. However, bitumen is extra heavy and almost solid at room temperatures. Unblended bitumen therefore cannot be sold via pipeline.
There are actually only three marketable crude oil blends derived from the oil sands: Dilbit, Synbit and Synthetic Crude.
Dilbit is a relatively clean bitumen (containing less than 1% water and solids) diluted with condensate, usually in the order of 30 to 40% by volume. Dilbit can only be processed by a high-conversion refinery and therefore sells at a discount to the US benchmark West Texas Intermediate (WTI). A majority of Alberta's exports are now Dilbit, mostly originating from in-situ operators.
Synthetic Crude Oil (SCO) is a light sweet crude produced by the upgrader, typically a blend of naphtha, distillate and gas oil streams from the hydrotreater. The term "synthetic" distinguishes upgraded bitumen from conventional crude, although the two crude streams are chemically identical. Since synthetic crude is light and sulphur-free, it can be sold to a conventional refinery. Synthetic crude sells approximately on par with WTI, representing about 40% of Alberta's production. The province's largest SCO producers are Syncrude, Suncor, Canadian Natural Resources and Shell.
Synbit is a mixture of synthetic crude and bitumen, typically a 50/50 blend. Since Synbit has a lower fraction of bitumen than Dilbit, it is slightly better in quality. Synbit volumes have diminished in recent years in favour of Dilbit production.
|CNRL Light Sweet Synthetic
Husky Synthetic Blend
Premium Albian Synthetic
Shell Synthetic Light
Suncor Synthetic A
Syncrude Sweet Premium
Hardisty Synthetic Crude
Synthetic Sweet Blend
|Access Western Blend
Borealis Heavy Blend
Christina Dilbit Blend
Cold Lake Blend
Kearl Lake Blend
Statoil Cheecham Blend
Western Canadian Select
|Long Lake Heavy
Statoil Cheecham Synbit
Surmont Heavy Blend
Albian Heavy Synthetic
Note that some blends, including Western Canadian Select, can also contain volumes of conventional crude. Depending on where the stream is blended, multiple operators may feed into a single crude stream.
All crude oil streams produced in Western Canada are assayed and catalogued by Crude Quality Inc., a private company in Edmonton in charge of monitoring product quality. The company's website (www.crudemonitor.ca) provides detailed sampling assays of each crude as well as historical averages.
COMPARING CRUDE STREAMS: HOW CRUDES ARE CLASSIFIED
Crudes are classified by their specific gravity (or density) and sulphur content:
Crude densities are described by their API gravity, measured as an inverse of specific gravity⁽¹⁾.
An API of 10° represents a crude density equivalent to water (1,000 kg/m³). Anything greater than 10° is lighter than water.
Crudes with an API gravity in the range of 42° to 50° are sometimes referred to as Super Light. Condensates typically have API gravity greater than 50°.
Sweet crudes contain less than 0.5% sulphur. Crudes with a higher sulphur content are referred to as sour.
< 870 kg/m3
22.3 - 31.1°
870 - 920 kg/m3
10 - 22.3°
920 - 1000 kg/m3
Extra Heavy Crude
> 1000 kg/m3
|Light Crude||31.1°||< 870 kg/m3|
|Medium Crude||22.3 - 31.1°||870 - 920 kg/m3|
|Heavy Crude||10 - 22.3°||920 - 1000 kg/m3|
|Extra Heavy Crude||< 10°||> 1000 kg/m3|
Crudes with an API density less than 10° is heavier than water and classified as an "extra heavy crude". Examples of extra heavy crudes include bitumen from Alberta and Boscán crude produced in Venezuela. Both have very poor flow properties at room temperatures and require significant dilution before transport.
Note that viscosity is also a function of density. A lower density crude is less viscous than a heavier crude and has better flow properties. However, viscosity is highly correlated to temperature, rising sharply as the temperature declines.
HOW THE BENCHMARKS STACK UP
A benchmark is defined as a crude stream of a specific quality that sells at a reference price from a given point of sale. There are about 200 benchmark streams of crude oil produced globally. The use of benchmarks allows for pricing comparison between crude streams of different qualities, produced in different parts of the world.
The most commonly referenced benchmarks are West Texas Intermediate (WTI), representing the US benchmark, and North Sea Brent, the international crude benchmark.
The two largest Canadian benchmarks are Western Canadian Select (WCS), a heavy sour blend and Canadian Light, a light sweet crude. The diluent commonly used to dilute bitumen is the CRW Condensate Blend, managed by Enbridge. CRW consists of field condensates, ultra-light sweet crudes and naphtha produced at various refineries and upgraders. CRW has an API gravity of about 65° with about 0.1% sulphur.
CANADIAN CRUDE PRICING DIFFERENTIALS EXPLAINED
Unlike other benchmark crudes, most Canadian crudes are traded in reference to the West Texas benchmark. Both Western Canadian Select and Canadian Light trade at a discount to WTI. Some streams such as Syncrude's Sweet Premium Blend will often trade at a premium. Edmonton condensate, depending on demand, typically trades relatively close to par.
Note that benchmark reference prices represent a specific point of sale. The WTI benchmark price is referenced from Cushing, Oklahoma. Brent crude is priced out of the North Sea. WCS is priced out of Hardisty, Alberta while Canadian Light reflects the price in Edmonton.
Therefore, a single crude benchmark will be priced differently at different locations, reflecting the transportation cost to that location.
PRODUCTION FROM THE OIL SANDS: LIGHT VS HEAVY CRUDE
As a general rule, most bitumen produced by mining is upgraded into light synthetic crude prior to being sold to refineries, while output from in-situ facilities is mostly diluted with condensate and sold directly to market without upgrading.
In 2016, only 16% of bitumen produced by mining was sold as diluted bitumen (without upgrading), mostly originating from Imperial Oil's Kearl Mine. Once the Fort Hills Mine comes into service in 2018, diluted bitumen volumes from mining is expected to almost double. By 2019, the fraction of mined bitumen sold without upgrading will increase to 24%.
In 2016, just 7.5% of in-situ bitumen production was upgraded into SCO, mostly from Suncor's MacKay River and Firebag SAGD operations. Beyond 2018, in-situ bitumen production is expected to dominate growth in the oil sands, adding to the volumes of diluted bitumen produced.
As a result, the fraction of Alberta bitumen upgraded into light synthetic crude will fall from a high of about 60% in 2007 to less than 40% in the next few years.
TRADE FLOWS: WHO BUYS ALBERTA CRUDE
In 2016, about 500,000 bbl/day of Alberta's crude oil was sold to Alberta refineries and chemical plants. Another 500,000 bbl/day was sold to refineries across Canada, mainly Ontario and Saskatchewan, with smaller volumes sold to BC and Quebec. The remaining 3.0 million bbl/day was sold to US refineries.
The Midwest refining hub (PADD 2) centred around Chicago is by far Canada's biggest customer. Most of the country's largest export pipelines funnel crude from Western Canada to the PADD 2 area, which has a refining capacity of just under 4 million bbl/day.
If/when Keystone XL is built, much more Canadian crude will flow to the Gulf Coast (PADD 3), one of the largest refining hubs in the world. The Gulf Coast has some of the world's most complex refineries, with a total refining capacity of about 9.6 million bbl/day. The region currently sources much of its heavy crude from Mexico and Venezuela (to a lesser extent) which will likely be displaced by Canadian heavy crude from the oil sands.
Exports of Canadian crude to non-US countries consist primarily of light conventional oil, mostly produced offshore Newfoundland. Exports of Alberta crude outside the US have so far been negligible, although that will likely change should the Trans Mountain Expansion be completed, which will send more blended bitumen to export markets in Asia. Trans Mountain will also send more Canadian crude to California refineries (PADD 5), which is largely cut-off from pipeline access and currently source most of their crude from overseas.
CANADIAN APPETITE FOR CANADIAN OIL
In 2016, about 40% of Alberta's upgraded bitumen was processed in Canadian refineries. In contrast about 95% of the province's heavy diluted bitumen is exported to the US. As heavy oil production from the oil sands continues to increase through the next decade, volumes of heavy oil exports to the US are also expected to rise. Crude volumes processed in Canadian refineries have held steady in recent years, although refineries in Quebec and Ontario have been less reliant on foreign crude due to the reversal of Line 9 in 2016.
Should TransCanada's Energy East pipeline be built, more Alberta crude will be processed in Canada. Irving's 300,000 bbl/day refinery in Saint John, NB currently runs on foreign crude, imported mostly from the Middle-East. Energy East would definitely help displace some of those imported volumes.
MARKETABILITY: WHY BEING HEAVY IS NOT NECESSARILY A BAD THING
About 80% of the crude produced in Western Canada is heavy, including 400,000 bbl/day from conventional sources and about 1.6 million bbl/day from the oil sands. As production of conventional light oil declines over the next decade and output from the oil sands increases, Canada's crude oil production will become increasingly heavier. But being heavy is not necessarily a bad thing.
Although it sounds counter-intuitive, refineries can actually make more money by processing heavy sour crude. Over the past 10 years, most refineries in the Gulf Coast and US Midwest have been modified into high-conversion facilities. These refineries crack and coke the heavy crude "bottoms" into high-value products, removing all traces of sulphur to produce expensive low-sulphur fuels. These highly complex facilities are specifically designed to process heavy sour feedstock, such as Western Canadian Select. In fact, refining margins are better with heavy crude feedstock than lighter oil.
DEMAND FOR HEAVY OIL: STRONG AND GETTING STRONGER
Over the past few decades, oil majors have been shutting down aged, simple refineries in countries like Europe and Canada. These refineries need light sweet crude, usually purchased at premium prices. Simple "topping" refineries therefore have lower refining margins and are generally less profitable.
As smaller refineries are decommissioned, highly complex mega-refineries have been constructed and expanded in recent years, in places like the Gulf Coast, India, China and throughout the Middle-East. In order to improve refining margins, these refineries source heavy sour crude, usually purchased at a slight discount. That's partly why the demand for heavy oil is so strong.
Globally, conventional light oil basins are in decline. As a result, the world's global oil supply is becoming increasingly heavier.
However, there is one huge exception. The recent growth in US oil production has largely come from shale, particularly the Permian, Bakken and Eagle Ford basins. Shale oil (often referred to as tight oil), is very light and sweet. This explosion of light oil production poses a problem for America's complex refineries, that are designed for heavy sour crude.
The solution? Blend the very light oil produced domestically with imports of very heavy oil, such as diluted bitumen produced in Canada. In fact, oil imports into the US have become increasingly heavier over the past few decades as demand for heavy oil has increased south of the border.
Note that most diluted bitumen streams from the oil sands have an API density in the low 20s (including WCS), classified as "medium" density crude according to EIA data. However, diluted bitumen is technically a heavy crude (bordering on medium), since most Dilbit streams have an API density below 22.3°.
About 50% of US imports have an API density between 20° and 30°, including diluted bitumen from the Alberta oil sands. In fact, over 80% of crude oil imports into the US are now light and heavy grades. The average API of crude produced domestically in the US is now about 40°.
In contrast, imports of light oil have declined considerably since the shale oil boom began in 2008. The government's recent lifting of the oil export ban has also enabled the US to export more light crude, producing a more desirable feedstock for US refineries. Imports of light oil have been cut in half over the past 15 years, falling to just 30% of total imports.
Although lighter crudes are generally considered to be "better quality", Alberta's largest export market has an excess domestic supply of light crude and a very healthy appetite for heavy and medium grades.
And that's why being heavy is not necessarily a bad thing.