Alberta's oil sands. It's the world's third
largest oil reserve. 161 billion barrels of recoverable oil in the ground. They're a
huge part of Canada's economy, contributing trillions to Canada's GDP over the past 50 years,
generating billions annually in government taxes, revenues, and royalties, supporting small and
medium-sized businesses from coast to coast and attracting hundreds of thousands of
workers from every part of the country But how much do you know about the oil sands? [Music] Alberta's oil sands are contained within
the Western Canadian Sedimentary Basin, which formed from the decomposition
of plants and marine life about 200 million years ago when Western Canada
was believed to be mostly underwater. Microbe bacteria, contained within the oxygenated
water, fed off the lighter hydrocarbon molecules, leaving behind a heavy complex
hydrocarbon known as bitumen. There are an estimated 1.8 trillion
barrels of oil in the oil sands, but only 10 percent of those barrels can be
economically recovered with current technology. That works out to 161 billion barrels
of recoverable oil in the ground. To put those numbers into context, the industry
currently extracts about a billion barrels a year, accounting for two-thirds of
Canada's total oil production Oil sands are a loose,
unconsolidated mixture of sand, clays, and water, saturated with bitumen.
Oil sands are mostly coarse silica sand, about 80 percent. Fine solids and clays make
up five percent, water is another five percent while bitumen saturation rates average about ten
percent. Bitumen is a hydrocarbon compound with a very long and very complex molecular structure.
Bitumen is high in carbon, low in hydrogen, and contains a relatively high amount of sulphur
and heavy metals, especially nickel and vanadium. Bitumen is an extra heavy oil and
contains as much as 20 percent asphaltenes, which are complex hydrocarbon
compounds, with a very high molecular weight. Asphaltenes are what make bitumen thick,
viscous, and almost solid at room temperatures, giving bitumen that smell of tar or asphalt.
While all crudes contain asphaltenes, bitumen has more asphaltenes than conventional
oil and even more than heavy conventional oil. To make oil from the oil sands, first
you extract the bitumen from the sand, then you either upgrade or dilute that
bitumen into a marketable crude product, which can then be shipped to a refinery for
final processing. There are two ways to extract bitumen from the oil sands - either by pumping
steam into the ground, which is referred to as situ extraction, or through surface mining. The
method used depends on the depth of the deposit. For deposits located deep underground,
steam is pumped into a well which extends deep into the reservoir. This steam heats up the
reservoir, reducing the viscosity of the bitumen, allowing it to be pumped up to the surface. This
mixture of bitumen and condensed steam is then sent to a processing plant, where the water is
separated from the bitumen, cleaned up and sent back to the steam plant, leaving behind a very
clean bitumen product. There are two types of in-situ technologies - the original cyclic steam
stimulation facilities, which use a single well for both steaming and bitumen production,
and the more common steam-assisted gravity drainage facilities, which use separate wells
for steam injection and bitumen production. Both produce a clean marketable bitumen, which is
diluted and sold to market as a heavy oil blend. About 20 percent of Alberta's oil sands are too
close to the surface to be extracted in-situ. In this case, traditional mining technology
is used to recover the bitumen. The mined oil sands is trucked to a processing plant using very
large haul trucks. The deposit is loosely crushed and then conveyed to a bitumen production
facility, where it's mixed with hot water, producing a pumpable slurry. Coarse sand is
gravity separated from the bitumen, and sent to a temporary tailing storage pond, where the
water can be recovered back to the process plant. Bitumen froth from extraction, which still
contains a lot of water and fine solids, is then mixed with a light hydrocarbon,
which reduces the viscosity of the bitumen, liberating most of the remaining fines and
water, leaving behind a relatively clean bitumen product. There are two types of mining facilities,
distinguished by the type of hydrocarbon used to clean the bitumen froth. The original naphthenic
facilities and the newer paraffinic facilities. NFT bitumen has way too much water
and solids to be pipelined very far, so that bitumen goes to a nearby upgrader.
However, PFT bitumen is very clean, so it's typically diluted with condensate and sold
directly to a refinery without being upgraded. Since bitumen from a traditional NFT mining
facility has too much water and solids, it can't be diluted to meet pipeline specifications. So it
can't be shipped very far. This bitumen therefore has to get processed in an upgrader, which is
usually located very close to the mine site. Aside from removing the solids, water and
hydrocarbon used in froth treatment, upgraders convert the bitumen residue, which is the sludge
left behind after crude distillation. Unlike the gas oil fractions, which are used to make gasoline
and diesel, residue doesn't evaporate very easily, and will produce a lot of lower value asphalt at
the refinery. And since bitumen is an extra heavy oil, it will produce a lot more sludge, even more
than conventional heavy oil. Upgraders basically upgrade or convert this residue into higher value
gas oils using equipment like crackers, cokers and hydro-conversion units which basically break
up the long chain hydrocarbon bonds, and improve the hydrogen to carbon ratio, either by removing
carbon or adding hydrogen. This converts the low value residue into higher value naphtha and gas
oils. The last step in the upgrading process is to take all of these streams and remove contaminants
that were originally contained in the bitumen, such as sulphur and nitrogen. After this cleaning
step, each stream is recombined into a final crude oil product known as synthetic crude, which is
a very clean residue-free light sweet crude. So just to recap, there are almost 30 in-situ
facilities and two PFT mining facilities that produce two million barrels per day of marketable
bitumen, which is diluted and sold as a dilbit blend, and four mining facilities which send their
bitumen to four upgraders, which produce about a million barrels per day of synthetic crude. That
all works out to about 3.5 million barrels per day of crude which is sold to refineries, including
the diluent portion. Starting with the 1 million barrels of light synthetic crude, about half gets
used in Canada, mostly Alberta, and the other half gets exported to the U.S., mostly the Midwest,
with smaller volumes going to Washington State. As for the two and a half million barrels
of dilbit that come from the oil sands, only a smidge goes to Canada. The bulk of it goes
to the U.S., and a large portion of that, more than two-thirds, ends up in the Midwest region,
because, well, that's just where the pipelines go. Canada has a lot of upgraders, which are basically
partial refineries, so Canadian refineries are better suited for synthetic crude, which has
already been partially refined. So that's why very little bitumen is processed in Canada. To
process bitumen, you need a very complex refinery, basically a refinery with a built-in
upgrader, just like the ones found in the U.S. western Canada has six crude export pipelines, all
originating from Alberta. Trans Mountain, which runs to the west coast, Rangeland, Milk River and
Express which run south to the Rocky Mountains region, and connect to the Midwest, Keystone,
which connects to the Gulf Coast via the Midwest, and Mainline, which runs to the Midwest and
also connects to the Gulf Coast. Well, let's look at the math. Excluding space for products,
the six pipelines have a total capacity of about 4 million barrels per day of crude. Western Canada
makes 4.8 million barrels, including diluent and conventional oil volumes, and regional refining
capacity is about 600,000 barrels per day. So that leaves 4.2 million barrels per day to
be shipped out to other customers. So, yeah, Canada is a bit short, at least until the Trans
Mountain Expansion comes online in 2023. [Music] Alberta makes a lot of dilbit, over 3.5 million
barrels per day, but local demand is very low, like 90,000 barrels, so all that excess has to
be exported. And when the pipelines are full, producers have to either store their oil, or ship
the extra barrels on railcars, and that all adds to the cost of shipping that oil to the customer,
which drops the oil price in Alberta [Music] Yes, there are many different oil prices,
depending on grade and demand for that particular grade at a particular location. In Alberta, for
example, the heavy oil discount averaged $13 a barrel in 2021, whereas in Houston,
that differential was only five bucks. That's because there's very little heavy oil
demand in Alberta and lots of supply, but heavy oil is very scarce in the Gulf Coast, while
refinery demand for heavy oil is very very high. If you're looking at the same grade, WCS for
example, then the price differentials reflect the cost of shipping that marginal barrel to the
final customer. So for WCS, that would basically be the cost of shipping that crude by pipeline,
assuming no other constraints in the system. In 2019, the oil sands emitted
84 megatons of co2 equivalent. That worked out to about 15 percent of Canada's
total emissions. Those emissions are split about half from in-situ operators and the other
half from mining and bitumen upgrading. Most of those emissions are from the burning
of natural gas for steam and power production, especially for in-situ operators. Diesel-powered
haul trucks and tailings ponds are a big source for mine operators, while upgraders burn fuel to
heat the bitumen feedstock to high temperatures. From extraction to the point of combustion, the
average U.S. barrel emits about 500 kilos of co2 equivalent per barrel. Remember that extraction
methods are only a small part of total emissions. Most of the carbon contained in a barrel of
oil are released at the point of combustion, so the average barrel refined in the U.S. is
actually on par with mature SAGD facilities like Cenovus's Christina Lake, and non-upgraded
oil sands mines like Imperial's Kearl Mine. Aside from improvements in efficiencies,
and technology advancements getting to zero emissions will likely come through carbon capture
and storage. All of the major oil sands producers have committed to being net zero by 2050 in
support of the federal government's mandate. Wow, that was a very quick 10-minute run through
Alberta's oil sands industry. Hi, my name is anna. I'm the editor of Oil Sands Magazine. If you're
looking for something more detailed I would invite you to check out our 101 Short Course, which
is in a similar format but a much slower pace. The course runs for about two hours, and
includes a downloadable PDF technical guide, and a transcript of the videos with links
to references and further reading material. And for a deeper dive into any of these topics,
you can always check out the technical library on our website, which is totally free. I'll leave
the links below. Thanks for watching. Bye for now.
