Opening up oilsands - extraction processes for the Canadian oilsands

Materials World magazine
1 Oct 2009

Nexen claims to be pioneering the next generation of oilsands development
in Canada. Michael Forrest reports

In the early Cretaceous period some 125 million years ago, a river system was developing in what is now Alberta, Canada. This river flowed north-south and eventually reached the Pacific, leaving many channels in which large sand deposits formed. As time progressed, the land subsided and the sea invaded the area, depositing near-shore sand banks. These fluvatile deposits lay on Devonian limestones that were eroded to an undulating surface, forming an unconformity to the later Cretaceous sands.

These sequences would not be uncommon in the geological record if it were not for the fact that the area contains the world’s largest deposit of oilsands with proven reserves calculated at over 170 billion barrels – making Canada second only to Saudi Arabia in terms of reserves.

How the oil filtered into the sands is not known, but it is thought to have originated in southern Alberta as crude oil that migrated about the same time that the Rockies were formed. Subsequent bacterial action and water converted the oil into a thick sticky bitumen. In the region of the Athabasca River, the oilsands are found in the McMurray Formation immediately above the unconformity. The formation is upward fining, with the lower member containing some 60m-thick discontinuous channel sands. A middle unit contains five to 10m units of sands, typical of a coastal plain environment with brackish water, while the upper unit marks the invasion of marine sedimentation.

In hot water

Above the McMurray, the Clearwater Formation comprises marine sediments with a basal glauconitic sand. There is evidence of a volcanic component, indicating a change of source region to the east. The oilsands occur over an area of 54,000 square miles, of which some 162 square miles has seen mining, this began in the 1920s when Dr Karl Clark was working with the Alberta Research Council to develop a hot water extraction process, which still offers the most economic recovery.

The oilsands of the McMurray Formation are 91-99% quartz with minor feldspar and kaolin, the latter mainly in the silt component that accounts for about 10%. The bitumen component comprises up to 19%, following the most permeable part of the sand channels and bars. Mining takes place north of Fort McMurray in the Athabasca River valley, where its incision allows machinery to access the oilsand formations with minimum (15m) overburden.

By the mid-1960s, the antecedent of Suncor Energy Inc, headquartered in Calgary, Alberta, mined the sands using bucket-wheel excavators from the coal mining industry. By the mid-1970s, Syncrude Ltd Canada, headquartered in Fort McMurray, began mining using draglines that offered a 60-fold increase in capacity over bucket-wheels. Regulations in Alberta require all mine waste and overburden to be rehabilitated into the mine site, and therefore the economics of mining confine operations to only a small area of less than 10% of the oilsands. Outside the river valley the overburden is too thick to allow open-pit mining. However, an equivalent to solution mining has been developed, based on Clark’s principles. It can be applied to those areas where the oilsands are too deep to mine, and is based on bitumen’s behaviour when subjected to heat – it flows.

Traditionally, mined sands are flushed with hot water or steam in tanks, which collect the bitumen that rapidly solidifies. After heat treatment, the clean bitumen is placed in a refining column much like that for crude oil where the bitumen is vapourised with each gaseous component condensing into oil products in turn. The final product is a liquid oil much like crude that can be used in a ‘normal’ refinery. Mining and moving the substantial amount of sand to recover the bitumen is, however, expensive, especially as the sands wear machinery rapidly.

The distribution of bitumen follows the sand channels within the McMurray Formation underlain by the limestone and capped by the Clearwater Formation sands and shales. This natural trap allows the injection of steam via a borehole and recovery of the bitumen/water mix using a hole drilled to a deeper level. The method is not without difficulty as bitumen viscosity is high enough to infill the grain boundaries and pore spaces, drastically reducing permeability within the highly differentiated sands resulting from fluvial deposition.

Steaming up

Another recovery method comes from Nexen Inc, a Calgary-based company with multinational interests. The company’s Long Lake oilsands facility uses steam-assisted gravity drainage (SAGD) – combination with proprietary OrCrude technology (from Opti Canada, Calgary), hydrocracking and gasification – to produce a premium synthetic crude oil.

Steam assisted gravity drainage (SAGD) was developed by Dr Roger Butler, an engineer at Canada’s Imperial Oil. It is a thermal method in which multiple well pairs are drilled horizontally parallel and vertically aligned. Their length is one to two kilometres with a vertical distance of around three metres. The upper level is the injection level, the lower the production well.

Steam is injected into both wells to allow the bitumen to flow, creating pore spaces that become filled, forming a steam chamber. Once fully steam-saturated, the flow to the lower well is stopped and continued in the upper well, forming a cone-shaped steam trap. Steam pressure is always below the fracture pressure of the rock and saturation pressure to prevent vapour from entering the production well. The process economically recovers approximately 55% of the contained bitumen.

One of the major costs of SAGD is from steam generation by natural gas. Other costs include those of the diluent for upgrading the recovered bitumen and its value on the open market. In 2004, Nexen began to employ OrCrude to obviate many of the above problems. It uses conventional distilling, solvent de-asphalting and thermal cracking to separate the bitumen into a partially upgraded sour crude and liquid coke. The latter is converted via the OrCrude process to a low-energy gas for use in the SAGD and as hydrogen.

Excess gas is used to produce electricity for onsite use and the provincial grid. The process is illustrated in the process flow diagram above, left. Overall the energy efficiency of the SAGD/OrCrude technology used at the Long Lake site is about 90%, compared to 75% for conventional bitumen-fed distilling (coking) plants.

The final product is a light-sweet crude oil that attracts premium prices. The results of these technologies can be seen in the production financials at Long Lake. Combined costs are predicted to average US$22/bbl, substantially lower than coking and other upgrading processes, while ongoing capital costs are between US$5 per barrel (bbl) and US$10 per barrel, dependent on well spacing. Long Lake received regulatory approval in 2003, with steam injection beginning in 2007 and SAGD production in 2008. That year Nexen produced 3,900bbls per day of bitumen, now increased, as of July 2009, to 18,000bbls per day, about one third of the planned plant capacity of 60,000bbls per day of synthetic crude.

Second generation

The successful implementation of the SAGD and OrCrude technologies by Nexen has brought the Athabasca oil sands into the second generation of recovery. The lowering of production costs, mainly driven by the savings on natural gas, means that the carbon footprint of oil from the sands, one of the major criticisms of the first generation of mined production has been substantially reduced. These methods also reduce the environmental impact of oil recovery with no overburden or sand waste requiring disposal in reclaimed minesites.

The joint venture’s 1,137km2 licences over oilsand lithologies in the Athabasca region are the target areas for future development. Investment in SAGD and OrCrude extends over a exclusive area of around 100 miles (166km) centred on Long Lake. Early in 2009, Nexen acquired an additional 15% interest in the joint venture, becoming sole operator of Long Lake and taking its share to 65%.

Further information: Nexen