For decades Canada has sat on one of the world's largest oil reserves, second only to the giant resource of Saudi Arabia. One third of the world's oil potential lies here.
But almost no one has paid it any heed, except a few diehard mining companies.
'It did not even rate on the US's official reserve lists until recently, ' says Ken Marsh, engineering and operations vicepresident for Meg Energy, one of a dozen or so new investor groups setting up new drilling and insitu extraction projects.
But then the 1.4 trillion barrels of underground bitumen are not as easily extracted as Gulf crude, where simply drilling into the desert produces a light, easily refinable oil.
Canada's oil is locked into thick and viscous underground sand deposits. 'At room temperature it's like molasses, ' says Marsh. 'It costs money to extract it, to separate it from the sand and then to process it.' Neither Meg Energy nor any of the other companies currently building steam injection and extraction plants will reveal how much money it does cost them, nor even exact investment figures. The level of returns is a sensitive subject on the Calgary oil finance markets.
'But the mining companies, which started operations in the 1960s, have kept going even at a $12 (£6.60) per barrel oil price, ' points out Brian Harrison, thermal heavy oil leader with a nearby project for Devon Energy, a US oil firm. Like Meg his project is near Fort McMurray 360km north of Edmonton, Alberta.
'With oil up above $50 or even $70 a barrel it becomes highly protable, ' he says.
Mining operations began further north, by oil company groupings like Suncor and Syncrude, that use open-cast on a huge scale to get at the oil, moving up to 70m depths of overburden and then millions of tonnes of sand, using the world's largest excavators and trucks like small blocks of flats.
The sand is mixed with warm water where it is separated from the bitumen. The bitumen is then either 'cracked' with additional hydrogen added catalytically to make it lighter or 'coked' to separate lighter fractions from a dense asphaltic residue. These processes require huge capital investment. But over 90% of oilsand layers lie up to 800m deep, beyond the reach of mining.
Methods to extract oil in situ have been under development since the 1980s, mostly using steam injection to soften the bitumen, although solvents have also been tried. First was Cyclic Steam Stimulation (CSS) where high pressure steam is forced into the ground for several weeks through a drill line. Hot melted bitumen and water are then pumped out over several months until the yield drops. Imperial Oil was the first user at a deposit at Cold Lake.
But in the 1990s the government-funded Alberta Oil Sands Technology & Research Authority developed the Steam Assisted Gravity Drainage (SAGD) method. It uses two parallel, porous cased drill holes, one 5m above the other, running horizontally.
'You inject steam into both to begin with but then only the top one, ' says Harrison. 'It melts the bitumen, which runs down to the lower line and is pumped out with the water.' The process uses lower pressure than CSS.
And by using runs of parallel drillings about 100m apart and 1km to 2km long, a large area can be covered from a small headworks.
'One of the key developments has been the renement of directional drilling, ' says Harrison. This, used with SAGD technology, means that projects are now coming on stream. They can win as much as 70% of the available resource.
'Most drilling platforms are in the muskeg, ' he explains.
This is the swampy ground of the northern plains forest, comprising 1m to 3m deep water and rotting timber, with scrawny black spruce growing through it. About 45% of the region is like it.
The central support plant for the platforms is substantial. For Harrison's Devon Oil Jack sh project this will be a C$550M (£264M), 35,000 barrels per day set up. A second phase will double this.
The plant produces steam for injection and separates the oil water mixture that comes back up the wells. Residual water is removed from the oil by standard technology and it is then diluted using gas condensate or synthetic crude.
'That makes it transportable in a pipeline, ' says Harrison.
Devon and Meg are cooperating on construction of local pipelines to export the mix and to import the 'diluent' as far as Edmonton. From there long-distance pipelines radiate outwards.
But Harrison says that the bulk of the site equipment is to clean up the water.
Water is recycled for economic and environmental reasons and to recover the residual energy it contains; it comes out of the ground at 200°C. Top-up water comes from saline non-potable aquifers.
'You have to heat nearly three barrels of water to get one of bitumen, ' he says. Natural gas, which is found in the area, is the main fuel, but it is expensive.
A series of heat exchangers and vessels use gravity, bafes and gas separation to break down emulsions and remove residual oil. Lime softening, and de-ionising remove silica and other minerals before the water goes to a bank of six steam makers.
These do not make dry steam.
A 20% water content remains.
This carries any residual minerals and is separated off to recirculate through the recovery cycle. Clean 15MPa steam goes through an insulated pipeline for injection at 5MPa.
At the Meg plant there will be just one steam unit, producing 3,000 barrels of oil per day when the plant comes on line in 2008.
'It is pilot plant scale, ' says March, 'but we will expand that to full size immediately afterwards.' The main project, like many others, will be a combined cycle generator plant producing electricity for plant use and sale to the grid. A total 140,000 barrels per day will eventually be achieved. Like Devon's project, the plant is being assembled from prefabricated modules manufactured in Edmonton.
This gives better quality control and is cheaper as labour shortages and severe conditions on site preclude in situ construction.
On site work involves mainly piling (Harrison has installed 3,200 precast concrete piles and Marsh the more usual steel tube piling), earthworks and some assembly of larger tanks as well as connection of the modularised pipe racks and components.