The Canadian oil sands host day at the beach
Billions of dollars, automation vendors, engineers, and technocrats pour into the boom town that is Fort McMurray
By Nicholas Sheble
In the beginning, the primordial ooze sat right on the surface of the earth in pools of black, tar-like gunk. It was tar, and it was gunk. It is bitumen.
It was so easy to get at that the Cree Indians spooned it off the ground, out of puddles, and coated their wooden canoes with the tar, thus waterproofing their rides.
It is not quite that simple to harvest the bitumen in the 21st century and certainly not as easy to capture as the sweet crude that explodes out of the ground in the Middle East.
Bitumen, however, can refine further to synthetic crude oil that then into one of the many petrochemical products sweet crude becomes, such as gasoline, diesel, and plastics. While the process is more laborious and expensive than that which is necessary for refining sweet crude, it is profitable at the current per barrel price ($126).
Squeezing oil south to north
Alberta’s oil sands are the largest-known reserve of oil in the world. There are 2 trillion barrels of oil there, with some estimates judging the reserve at closer to 3 trillion barrels. At present world usage rates, that is over 90 years worth. It resides in a difficult mixture of sand, water, and clay. The Alberta government postulates “this vast resource came about because light crude oil from southern Alberta migrated north and east with the same pressures that formed the Rocky Mountains.”
Over time, the actions of water and bacteria transformed the light crude into bitumen, a much heavier, carbon rich, and extremely viscous oil. The percentage of bitumen in oil sand can range from 1-20%.
The oil saturated sand deposits left over from ancient rivers in three main areas, Peace River, Cold Lake, and Athabasca. The Athabasca area is the largest and closest to the surface, accounting for the large-scale oil sands development around Fort McMurray. It is here Suncor recovers bitumen from oil sands and upgrades it to refinery-ready feedstock and diesel fuel.
Suncor pioneered the world’s first commercially successful oil sands operation in 1967 and has produced over 1 billion more barrels since. By last year, production at the oil sands facility averaged 235,600 barrels per day. The company recently announced a $20.6 billion investment that will boost crude oil production to 550,000 barrels per day in 2012.
Mining never stops
Open pit mining of the oil sands started in the 1920s. The first large scale commercial operation, Great Canadian Oil Sands (now Suncor Energy), introduced bucket wheels from the coal mining industry when they opened in 1967.
Syncrude Canada Limited opened in 1978 and introduced gigantic draglines that connected to the processing plant by a system of conveyor belts. This method eventually became uneconomical and not viable.
Now large trucks and shovels have replaced draglines and bucket wheels as a more selective and cost effective way to mine oil sands. The process begins by clearing trees, draining and storing the overburden, and then removing this top layer of earth thereby exposing the ore.
Mining never stops; the trucks and other equipment work day and night, every day of the year. The trucks dump their loads into enormous hoppers, the load goes through a grinder, and it then transfers by belt to conditioning.
In this step, any large lumps of oil sand are broken up, and the removal of any coarse material takes place. The oil sand then mixes with water to form a slurry.
One of the earlier methods to condition oil sand was to mix it with hot water in huge tumblers or conditioning drums. The tumblers introduced air into the slurry and screened it to remove coarse material.
A newer approach, and the one Suncor uses at its Athabasca plant, eliminates tumblers or conditioning drums altogether.
After crushing the oil sand, it mixes with warm water and then it moves by pipeline to the extraction plant. This piping system is hydrotransport, and it is a valuable new tool in the oil sands process.
Hydrotransport is cost effective and efficient. It replaces the old conveyor system between the mine and the extraction plant. It combines two steps into one.
It conditions the oil sand while moving it to extraction. The water used for hydrotransport is cooler than in the tumblers or conditioning drums, further reducing energy costs.
Both these methods of conditioning are important in that they start complex physical and chemical changes. Conditioning starts the separation of the bitumen from the sand by breaking the bonds that hold the bitumen, water, and sand together.
The slurry separates as it transfers in the pipe into four layers. On top is the oil, then water, sand, and heavier particulate like rocks. The four layers move at different velocities, and they all develop their own laminar flow profiles.
To get an accurate view of the flow, volume, and densities, Suncor mounts non-invasive nuclear gauges sitting on a diagonal—from 1 o’clock to 7 o’clock on the pipe. This way the beam passes through the different layers and flows in the pipe.
Hydrotransporting is terrifically hard on pipes, and wear most occurs at the bottom of the pipe where the heavier part of the slurry is moving and bumping along. In order to balance the wear, maintenance periodically rotates the pipes so they wear and wear out evenly.
A truly unique process
The blended slurry now feeds into the primary separation vessel (PSV) where it is settles into three layers. Additional hot water adds in as the slurry arrives. This promotes a more rapid separation.
Impure bitumen froth floats on top, sand sinks to the bottom, and a combination of bitumen, sand, clay and water sits in the middle. The settling and separation takes approximately 20 minutes. The PSV has a rake at the bottom that pulls the sand down and speeds up the separation. The sand, mixed with water, transfers to settling basins—tailings ponds.
The middlings is a suspended mixture of clay, sand, water, and some bitumen. The middlings go through a process of secondary separation. There are different methods to this process, but they rest on the injection of air into the middlings in flotation tanks.
This added air encourages the creation of additional bitumen froth in the effort to recover another 2-4% of bitumen. Bitumen from the secondary recovery system recycles back to the primary system.
Steam heats the froth and removes excess air bubbles, in a vessel—the deaerator. This removes air enabling the pumps to operate efficiently and without cavitation.
Bitumen froth contains about 30% water and 10% solids. Deaerated bitumen froth from the extraction area sees further cleaning and the removal of solids and water in the froth treatment plant.
At the froth-treatment plant, they add naphtha to the bitumen to make it flow easily, and then the mixture goes through a combination of inclined plate settlers and centrifuges.
Inclined plate settlers allow for particles to settle efficiently under gravity, in a relatively small vessel by increasing settling area with inclined plates. A centrifuge uses centrifugal force to spin heavier materials outward.
There are two types of centrifuge in operation in froth treatment. The first, the scroll centrifuge, spins out coarser particles and uses an auger like action to convey solids out of the machine. The disc centrifuge removes the finer material including very small water droplets. It works like a spin cycle on a washing machine and spins the remaining solids and water outward and they pass on to tailings pond.
The clean diluted bitumen product is now dry containing less than 5% water and with few solids. This extraction process is complete.
This hot water extraction process recovers over 91% of the bitumen contained in the oil sand feed. The bitumen is now ready to for upgrading process and the promotion synthetic crude oil.
Way down under is the bulk
About 80% of the oil sands in Alberta are too deep below the surface for open pit mining. To recover this oil, companies use in situ techniques.
Using drilling technology, steam injects into the deposit to heat the oil sand lowering the viscosity of the bitumen. The hot bitumen migrates towards producing wells, bringing it to the surface, while the sand remains in place.
Steam assisted gravity drainage is a type of in situ technology that uses innovation in horizontal drilling to produce bitumen. In situ technology is expensive and requires certain conditions like a nearby water source.
Production from in situ already rivals open pit mining and in the future may well replace mining as the main source of bitumen production from the oil sands.
Challenges facing in situ process are efficient recoveries, management of water used to make steam, and co-generation of all heat sources to minimize energy costs.
Other methods of in situ recovery look promising, but they are in research stages of development.
ABOUT THE AUTHOR
Nicholas Sheble (firstname.lastname@example.org) is senior technical editor at InTech. Sources for this article were Suncor, Oil Sands Discovery Centre, and the Canadian Energy Research Institute.
In situ: Subterranean oil technology
Canada’s long-term energy future depends to a large extent on the development of economical in situ recovery processes to tap Alberta’s vast oil sands reserves.
Varieties of in situ methods are working to recover bitumen, especially from deposits too deep to surface mine.
All in situ approaches face two major challenges. How can we reduce the viscosity of the bitumen so it will flow? In addition, how can we recover the bitumen? Different deposits may favor different production methods.
Today, two major in situ techniques, cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD), are working commercially in Alberta’s oil sands.
Production figures show the growing importance of in situ methods. Today, total in situ production rivals production from mining oil sands; and in the near future, most believe in situ operations will produce more bitumen than mining.
CSS injects high-pressure, high-temperature (about 350°C) steam into oil sand deposits. The pressure of the steam fractures the oil sand, while the heat of the steam melts the bitumen.
As the steam soaks into the deposit, the heated bitumen flows to a producing well, and that well pumps it to the surface. This process can happen several times over in a formation, and it can take between 120 days and two years to complete a steam stimulation cycle.
SAGD is the most popular enhanced oil recovery technology currently in use by Canadian heavy oil producers.
An estimated 1 trillion barrels of oil in the Athabasca deposit are potentially recoverable with the present technology.
Surface mining is only feasible for recovering up to 20% of the oil sands deposits, making SAGD the best-known alternative for recovering the potential 80% of the remaining oil sands deposits.
SAGD technology requires the drilling of two parallel horizontal wells through the oil-bearing formation. Into the upper well, they inject steam creating a high-temperature steam chamber.
The increased heat loosens the thick crude oil causing it to flow downward in the reservoir to the second horizontal well. This second well is located parallel to and below the steam injection well.
This heated, thinner oil then pumps to the surface via the second horizontal, or production well. Water fills the bitumen-drained area to maintain the stability of the deposit.
Toe to heal air injection (THAI) technology offers many potential advantages over SAGD, including higher resource recovery of the original oil in place, lower production and capital costs, minimal usage of natural gas and fresh water, a partially upgraded crude oil product, reduced diluent requirements for transportation, and significantly lower greenhouse gas emissions.
The THAI process also has potential to operate in reservoirs lower in pressure, containing more shale, lower in quality, thinner, and deeper than SAGD.
This type of technology could work in deep heavy oil resources both onshore and offshore.
The Vapor extraction process (VAPEX) is a technology similar to SAGD, but instead of steam, solvent injects into the oil sands resulting in significant viscosity reduction.
The injection of vaporized solvents such as ethane or propane help create a vapor-chamber through which the oil flows due to gravity drainage. The process can be applied in paired horizontal wells, single horizontal wells, or a combination of vertical and horizontal wells.
The key benefits are significantly lower energy costs, potential for in situ upgrading and application to thin reservoirs. The outstanding technical challenges are it has yet to be field-tested and field injection and production strategies have yet to be developed.
Source: Oil Sands Discovery Center
Bitumen is petroleum that exists in the semisolid or solid phase in natural deposits. It is the molasses-like substance that can comprise anywhere from 1 to 18% of the oil sand.
Conventional crude oil is petroleum found in liquid form, flowing naturally or capable of being pumped without further processing or dilution.
Extraction is the process of separating the bitumen from the oil sands.
Hydrocarbons: A large class of liquid, solid, or gaseous organic compounds containing only carbon and hydrogen, which are the basis of almost all petroleum products
Hydrotransport is the process whereby oil sand from the mine operation mixes with hot water and caustic, and this oil sand slurry then is transported by pipeline to the extraction plant where it feeds directly into the primary separation vessel.
In situ is a Latin phrase meaning “in the place,” “in its original place,” and “in position.” In situ recovery refers to various methods used to recover deeply buried bitumen deposits, including steam injection, solvent injection, and firefloods.
Naphtha: Any of various volatile, often flammable, liquid hydrocarbon mixtures used chiefly as solvents and diluents
Synthetic crude oil is a mixture of hydrocarbons, similar to crude oil, derived by upgrading bitumen from oil sands.
Tailings is the combination of water, sand, silt, and fine clay particles that are a byproduct of removing the bitumen from the oil sand.
Return to Previous Page